CONNECTICUT LIGHT & POWER CO - Annual Report: 2007 (Form 10-K)

Name and
Principal Position

Team Goal
Weighting

Individual
Goal
Weighting

Brief Description of Material Individual Goals

Charles W. Shivery

Chairman of the Board, President, and Chief Executive Officer of NU; Chairman of CL&P

Ensure effective execution of the company’s strategic plan and the operating and capital plans (30% of individual goals).

Achieve successful outcomes in federal and state energy regulatory policy and ratemaking proceedings; develop comprehensive communications strategy regarding critical issues (20% of individual goals).

Achieve progress in continued development and implementation of energy policy in New England (20% of individual goals).

Implement strategic planning organization to create decision making framework to evaluate strategic options available to the company (15% of individual goals).

Focus on workforce management and effective pay for performance; meet company objectives for safety, diversity and the environment (15% of individual goals).

David R. McHale

Senior Vice President and Chief Financial Officer

Strategic initiatives: Operational planning, risk management, and capital allocation (25% of individual goals).

Business execution: Lead efforts in rate cases, regulatory strategy, energy policy, and corporate cost analysis and management (40% of individual goals).

Financial organization: Reorganize corporate finance function and related financial improvement initiatives (20% of individual goals).

Competitive business divestiture (15% of individual goals).

NU 2007 FORM 10-K

____________________________________________________________________________________

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K


[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Fiscal Year Ended December 31, 2007
	OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________


Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.

1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone: (413) 785-5871	04-2147929

0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone: (860) 665-5000	06-0303850

1-6392	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone: (603) 669-4000	02-0181050

0-7624	WESTERN MASSACHUSETTS ELECTRIC COMPANY (a Massachusetts corporation) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone: (413) 785-5871	04-1961130

Securities registered pursuant to Section 12(b) of the Act:


Registrant	Title of Each Class	Name of Each Exchange on Which Registered

Northeast Utilities	Common Shares, $5.00 par value	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:


Registrant	Title of Each Class

The Connecticut Light and Power Company	Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are outstanding:


$1.90	Series	of 1947
$2.00	Series	of 1947
$2.04	Series	of 1949
$2.20	Series	of 1949
3.90%	Series	of 1949
$2.06	Series E	of 1954
$2.09	Series F	of 1955
4.50%	Series	of 1956
4.96%	Series	of 1958
4.50%	Series	of 1963
5.28%	Series	of 1967
$3.24	Series G	of 1968
6.56%	Series	of 1968

Public Service Company of New Hampshire and Western Massachusetts Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.


	Yes	No

	Ö

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.


	Yes	No

		Ö

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.


	Yes	No

	Ö

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ Ö ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer

Northeast Utilities	Ö
The Connecticut Light and Power Company			Ö
Public Service Company of New Hampshire			Ö
Western Massachusetts Electric Company			Ö

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).


	Yes	No

Northeast Utilities		Ö
The Connecticut Light and Power Company		Ö
Public Service Company of New Hampshire		Ö
Western Massachusetts Electric Company		Ö

The aggregate market value of Northeast Utilities’ Common Shares, $5.00 Par Value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities’ most recently completed second fiscal quarter (June 30, 2007) was $4,391,733,431 based on a closing sales price of $28.36 per share for the 154,856,609 common shares outstanding on June 30, 2007. Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.

Indicate the number of shares outstanding of each of the registrants' classes of common stock, as of the latest practicable date:


Company - Class of Stock	Outstanding at January 31, 2008
Northeast Utilities Common shares, $5.00 par value	155,153,646 shares

The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares

Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares

Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

Documents Incorporated by Reference:


Description		Part of Form 10-K into Which Document is Incorporated

Portions of Annual Reports of the following companies for the year ended December 31, 2007:

	Northeast Utilities	Part II
	The Connecticut Light and Power Company	Part II
	Public Service Company of New Hampshire	Part II
	Western Massachusetts Electric Company	Part II

Portions of the Northeast Utilities Proxy Statement dated March 31, 2008		Part III

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in this report:

COMPANIES


Boulos	E. S. Boulos Company
CL&P	The Connecticut Light and Power Company
Con Edison	Consolidated Edison, Inc.
CRC	CL&P Receivables Corporation
CYAPC	Connecticut Yankee Atomic Power Company
Globix	Globix Corporation
HWP	Holyoke Water Power Company
Mt. Tom	Mt. Tom generating plant
MYAPC	Maine Yankee Atomic Power Company
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company and subsidiaries
NU or the company	Northeast Utilities
NU Enterprises	NU Enterprises, Inc. is the parent company of Select Energy, Inc. (Select Energy), the E. S. Boulos Company (Boulos), Northeast Generation Services Company (NGS) and Select Energy Contracting, Inc. (SECI).
NUSCO	Northeast Utilities Service Company
Parent and other companies	Parent and other companies is comprised of NU parent, Northeast Utilities Service Company, HWP (since January 1, 2007) and other subsidiaries, including Rocky River Realty Company and the Quinnehtuk Company (both real estate subsidiaries), Mode 1 Communications, Inc. (telecommunications) and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company), Yankee Energy Financial Services Company, and NorConn Properties, Inc.
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH, WMECO, the generation segment of PSNH, and Yankee Gas, which is a natural gas local distribution company. For further information, see Note 16, "Segment Information," to the consolidated financial statements.
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc.
SESI	Select Energy Services, Inc.
Woods Electrical	Northeast Acquisition Company, formerly Woods Electrical Co., Inc. a portion of the business of which was sold in April of 2006 and the remainder of which was wound down in the second quarter of 2007.
WMECO	Western Massachusetts Electric Company
Woods Network	Woods Network Services, Inc.
YAEC	Yankee Atomic Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Companies	CYAPC, MYAPC and YAEC
Yankee Gas	Yankee Gas Services Company

MILLSTONE UNITS


Millstone 1	Millstone Unit No. 1, a 660 megawatt nuclear unit completed in 1970; Millstone 1 was sold in March of 2001.
Millstone 2	Millstone Unit No. 2, an 870 megawatt nuclear electric generating unit completed in 1975; Millstone 2 was sold in March of 2001.
Millstone 3	Millstone Unit No. 3, a 1,154 megawatt nuclear electric generating unit completed in 1986; Millstone 3 was sold in March of 2001.

REGULATORS


CDEP	Connecticut Department of Environmental Protection
DOE	United States Department of Energy
DPU	Massachusetts Department of Public Utilities (formerly the Massachusetts Department of Telecommunications and Energy (DTE))
DPUC	Connecticut Department of Public Utility Control
FERC	Federal Energy Regulatory Commission
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission

OTHER


AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
CfD	Contract for Differences
CTA	Competitive Transition Assessment
COLA	Cost of Living Adjustment
EDIT	Excess Deferred Income Taxes
EPS	Earnings Per Share
ES	Default Energy Service
FASB	Financial Accounting Standards Board
FIN	FASB Interpretation No.
GSC	Generation Service Charge
GWH	Gigawatt Hours
FMCC	Federally Mandated Congestion Charges
ISO-NE	New England Independent System Operator or ISO New England, Inc.
ITC	Investment Tax Credits
KWH or kWh	Kilowatt-hour
KV	Kilovolt
LNG	Liquefied Natural Gas
LNS	Local Network Service
LOC	Letter of Credit
MGP	Manufactured Gas Plant
MMCF	Million Cubic Feet
MW	Megawatts
NYMPA	New York Municipal Power Agency
PBO	Projected Benefit Obligation
PBOP	Postretirement Benefits Other Than Pensions
PCRBs	Pollution Control Revenue Bonds
Money Pool or Pool	Northeast Utilities Money Pool
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission segment.
Restructuring Settlement	"Agreement to Settle PSNH Restructuring"
RMR	Reliability Must Run
RNS	Regional Network Service
ROE	Return on Equity
RTO	Regional Transmission Operator
SBC	System Benefits Charge
SCRC	Stranded Cost Recovery Charge


SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
TCAM	Transmission Cost Adjustment Mechanism
TSO	Transitional Standard Offer
UI	The United Illuminating Company
UITC	Unamortized Investment Tax Credits
VIE	Variable Interest Entity

iii

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

2007 Form 10-K Annual Report
Table of Contents


	Part I	Page

Item 1.	Business	1
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	25
Item 4.	Submission of Matters to a Vote of Security Holders	28
	Part II

Item 5.	Market for the Registrants' Common Equity and Related Stockholder Matters	29
Item 6.	Selected Financial Data	30
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	30
Item 8.	Financial Statements and Supplementary Data	32
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	32
Item 9A.	Controls and Procedures	32
Item 9B.	Other Information	33
	Part III

Item 10.	Directors, Executive Officers and Corporate Governance	34
Item 11.	Executive Compensation	36
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
Item 13.	Certain Relationships and Related Transactions, and Trustee Independence	73
Item 14.	Principal Accountant Fees and Services	74
	Part IV

Item 15.	Exhibits and Financial Statement Schedules	76
Signatures		77

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions or future events, performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our "forward-looking statements" through the use of words or phrases such as "believe," "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels and timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of our remaining competitive electricity positions, actions of rating agencies, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports filed with the Securities and Exchange Commission (SEC) and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties which may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, "Risk Factors" included in this report. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanying "Management’s Discussion and Analysis" and "Notes to Consolidated Financial Statements." We encourage you to review these items.

PART I

Item 1. Business

NU, headquartered in Berlin, Connecticut, is a public utility holding company registered with the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned regulated utility subsidiaries:

The Connecticut Light and Power Company (CL&P), a regulated electric utility which serves residential, commercial and industrial customers in parts of Connecticut.

Public Service Company of New Hampshire (PSNH), a regulated electric utility which serves residential, commercial and industrial customers in parts of New Hampshire.

Western Massachusetts Electric Company (WMECO), a regulated electric utility which serves residential, commercial and industrial customers in parts of western Massachusetts; and

Yankee Gas Services Company (Yankee Gas), a regulated gas utility which serves residential, commercial and industrial customers in parts of Connecticut.

We sometimes refer to CL&P, PSNH, WMECO and Yankee Gas collectively in this Annual Report on Form 10-K as the "regulated companies."

NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises, Inc. (NU Enterprises). We have exited most of these businesses. As of December 31, 2007, NUEI’s remaining business consisted of (i) Select Energy Inc.’s (Select Energy) few remaining wholesale marketing contracts, and (ii) NU Enterprises’ remaining energy services business.

Although NU consolidated, CL&P, PSNH and WMECO report their financial results separately, we also include information in this report on a segment, or line of business basis. The regulated companies include three business segments: the electric distribution segment (which includes PSNH’s regulated generation activities), the natural gas distribution segment and the electric transmission segment. The regulated companies’ segment of our business represented approximately 92.8% of our total earnings for 2007, with electric distribution (including PSNH’s generation activities) representing approximately 50.1%, electric transmission representing approximately 33.5% and natural gas transmission representing approximately 9.2%. At December 31, 2007, the NU Enterprises business segment included the following legal entities: (i) Select Energy, Inc. (Select Energy), (ii) Northeast Generation Services Company (NGS), (iii) E.S. Boulos Company (Boulos), (iv) the remaining business of Select Energy Contracting, Inc. (SECI) and (iv) NU Enterprises parent.

For information regarding each of NU’s segments, see Note 16, "Segment Information," contained within NU's 2007 Annual Report to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

REGULATED ELECTRIC DISTRIBUTION

General

CL&P, PSNH and WMECO, sometimes referred to herein as the "operating companies", are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts, respectively, with PSNH also participating in the regulated electric generation business. The following table shows the sources of 2007 electric franchise retail revenues for the operating companies, collectively, based on categories of customers:


Sources of Revenue		Total Operating Companies
Residential		54%
Commercial		36%
Industrial		9%
Other		1%
Total		100%

A summary of changes in the operating companies’ electric kilowatt-hour (kWh) sales for the 12-month period ended December 31, 2007 as compared to December 31, 2006 on an actual and weather normalized basis is as follows:


	Electric
	CL&P		PSNH		WMECO		Total
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	2.8 %	0.4 %	2.9 %	1.5 %	1.9 %	(0.3)%	2.7 %	0.6 %
Commercial	1.3 %	0.8 %	1.8 %	1.6 %	1.0 %	0.5 %	1.5 %	1.0 %
Industrial	(1.3)%	(1.5)%	(3.4)%	(3.2)%	(2.3)%	(2.4)%	(2.0)%	(2.1)%
Other	6.9 %	6.9 %	4.9 %	4.9 %	- %	- %	6.2 %	6.2 %
Total	1.7 %	0.4 %	1.2 %	0.6 %	0.6 %	(0.4)%	1.5 %	0.4 %

Our electric sales per customer, adjusted for weather impacts, have been negatively affected by retail rate increases driven by the energy component of customer bills that began in early 2006. Although, the longer-term trend in customer usage in our service territory when energy prices were stable had reflected a generally increasing use per customer, customers have responded to higher energy prices in recent years by using less electricity. Even though generation costs stabilized in 2007, use per customer did not change significantly from 2006 levels, reflecting continued conservation efforts. Sales growth in 2007 was primarily driven by growth in the number of customers as opposed to use per customer. We cannot determine at this time if these trends will continue or the effect they may have on our distribution segment earnings.

THE CONNECTICUT LIGHT AND POWER COMPANY

Distribution

CL&P is engaged in the purchase, transmission, delivery and sale of electricity to its residential, commercial and industrial customers. At December 31, 2007, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut. CL&P does not own any electric generation facilities.

The following table shows the sources of 2007 electric franchise retail revenues for CL&P based on categories of customers:


CL&P
Residential		57%
Commercial		36%
Industrial		6%
Other		1%
Total		100%

Rates

CL&P is subject to regulation by the Connecticut Department of Public Utility Control (DPUC) which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to cover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, competitive transition assessment (CTA) and other charges that are assessed on all customers. Such rates also include an electric generation service component, which includes the cost of power supply which CL&P purchases for customers that do not choose to be served by a competitive retail supplier. As a result of Connecticut legislation passed in July 2005, CL&P filed for a transmission adjustment clause on August 1, 2005. On December 20, 2005, the DPUC approved the tracking mechanism, which provides for semi-annual adjustments in January and July of each year. CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. (See "Regulated Electric Transmission" in this Annual Report on Form 10-K).

CL&P has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred stranded costs, which are pre-restructuring expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates. CL&P has financed a significant portion of its stranded costs through the issuance of rate reduction certificates secured by its right to recover stranded costs over time (securitization). CL&P recovers the costs of securitization through the CTA component of its rates. In addition to those being recovered through securitization, CL&P’s stranded costs, included, as of December 31, 2007, ongoing independent power producer costs and costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units.

Under state law, all of CL&P's customers are entitled to choose their energy suppliers while retaining CL&P as their distribution company. CL&P purchases power for, and passes through the cost to those customers who do not choose a competitive energy supplier. Beginning January 1, 2007, this service was termed "Standard Service" for customers with less than 500 kW of demand and "Supplier of Last Resort Service" for customers with 500 kW of demand or greater. CL&P receives the cost for this service through the "Generation Service Charge" and "Bypassable Federally Mandated Congestion Charge" (FMCC) components of the customer’s bill, which is adjusted and reconciled on a semi-annual basis.

A large percentage of CL&P's customers have continued to buy their power from CL&P at Standard Service or Supplier of Last Resort rates. However, CL&P is experiencing some customer migration to competitive energy suppliers, with the movement concentrated among the larger customers. As of December 31, 2007, approximately 69,000 customers or 6% out of 1.2 million, representing approximately 33% of December 2007 load, had selected competitive energy suppliers. This customer migration is for energy supply service only so there is no impact on the delivery portion of the business or the operating income of CL&P. Energy supply service costs have been, and remain a 1-for-1 pass-through cost with no return.

On July 30, 2007, CL&P filed an application with the DPUC for an increase in its distribution rates, including an authorized regulatory return on equity (ROE) of 11% and a proposed capital budget of approximately $294 million for 2008 and $288 million for 2009. CL&P’s application also contained, as required by Connecticut Public Act 07-242, "An Act Concerning Electricity and Energy Efficiencies" (Energy Efficiency Act), a proposal to implement distribution revenue decoupling from the volume of electricity sales using a revenue per customer tracking mechanism. On January 28, 2008, the DPUC issued its decision in the proceeding. The decision approved annualized increases in CL&P’s distribution rates of $77.8 million for 2008 and $20.1 million for 2009, and a regulatory ROE of 9.4%, with CL&P continuing the existing earnings sharing mechanism, which provides that ratepayers and shareholders share equally in any earnings in excess of its allowed regulatory ROE. The decision also approves substantially all of CL&P’s proposed capital budget. In its decision, the DPUC did not approve CL&P’s proposal to achieve decoupling using a "revenue per customer" adjustment mechanism. In lieu of this proposal, the DPUC authorized compliance with the decoupling provisions of the Energy Efficiency Act via rate design that includes greater fixed recovery of distribution revenue. As compared to previous tariffs, CL&P's new distribution rates are intended to recover proportionately greater revenue through the fixed Customer and Demand charges and proportionately less distribution revenue through the per kWh charges. The new 2008 rates took effect on February 1, 2008, and the 2009 increase will take effect on February 1, 2009.

Regulatory Update

On March 30, 2007, CL&P filed a metering compliance plan with the DPUC that would meet the DPUC's objective of making time-of-use rates available to all CL&P customers. CL&P's filing discussed the technology, implementation options and costs comparing an open advanced metering infrastructure (AMI) system deployed on a geographic basis to a fixed automated metering reading (AMR) network system deployed on a usage-based priority schedule. The plan provided for full deployment by 2010. On July 2, 2007, CL&P filed a revised AMI plan consistent with the requirements of the Energy Efficiency Act, which provided for a less aggressive implementation schedule based on customer interest and allowed for future DPUC input at various milestones. CL&P requested cost recovery through its FMCC. On December 19, 2007, the DPUC issued a final decision on CL&P’s compliance plan that authorized a pilot program involving the installation of 10,000 AMI meters and a rate design pilot to test new time-of-use and real-time rates to determine customer acceptance and load response to various pricing structures. For further information on CL&P rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

In April 2007, pursuant to Public Act 05-01, "An Act Concerning Energy Independence" (Energy Independence Act), CL&P entered into a 15-year contract to purchase energy, capacity and renewable energy credits from a biomass energy plant beginning after completion of the plant. The contract has been approved by the DPUC and it provides for annual purchases of up to approximately 15 megawatts (MW) The DPUC has approved a sharing agreement between CL&P and The United Illuminating Company (UI) under which they will share the net costs and benefits of this contract and other contracts ultimately entered into under this program, with approximately 80% to CL&P and approximately 20% to UI, regardless of which contracts are signed by CL&P and which contracts are signed by UI. CL&P's portion of the net costs or net benefits of such contracts will be paid by or returned to CL&P's customers.

On January 30, 2008, the DPUC issued a decision approving contracts with seven more renewable energy projects of different designs totaling approximately 109 MW. The DPUC also gave contingent approval of a contract with another renewable energy project representing approximately 20 MW. The DPUC’s contingent approval of this contract would become final if one or more of the seven projects having an approved contract (representing at least 20 MW) is unable to obtain a financing commitment letter. CL&P's share of the future costs or benefits under all these contracts will be paid by or refunded to CL&P's customers. A third round of solicitations is expected to be conducted by the Connecticut Clean Energy Fund (CCEF) for an additional 26 MW of recoverable energy generation by October 1, 2008.

Also pursuant to the Energy Independence Act, the DPUC conducted a request for proposal process and selected three generating projects to be built or modified that would be eligible to sign contracts for differences (CfDs) with CL&P and UI for a total of approximately 782 MW of capacity. The process also selected one new 5 MW demand response project. The CfDs obligate CL&P or UI to pay the difference between a set capacity price and the value that the projects receive in the New England Independent System Operator (ISO-NE) capacity markets. The terms of the contracts are for periods of up to 15 years and would be subject to another similar sharing agreement between CL&P and UI. These contracts have been approved by the DPUC and signed by either CL&P or UI, whichever is the primary

obligor. CL&P’s portion of the costs and benefits of these contracts will be paid by, or refunded to, CL&P’s customers. On October 5, 2007, NRG Energy, Inc. filed an appeal of the DPUC's decision selecting the generation projects. On February 13, 2008, the Superior Court dismissed NRG’s appeal.

The Energy Efficiency Act requires CL&P and UI to negotiate in good faith to potentially enter into cost-of-service based contracts for the energy associated with the three above-mentioned generation projects that were awarded CfDs by the DPUC, for term lengths equivalent to the associated CfDs. These energy contracts must be approved by the DPUC after a finding that they will stabilize the cost of electricity for Connecticut ratepayers. Depending on its terms, a long-term contract to purchase energy from a project that is also under a CfD could result in CL&P consolidating these projects into its financial statements. CL&P would seek to recover from customers any costs that result from consolidation of a project. As of February 1, 2008, only one of the three CfD project developers has requested that CL&P enter into negotiations for such a contract. For further information, see Notes 5 and 3, "Derivative Instruments," to our consolidated financial statements contained in NU’s and CL&P’s Annual Report to Shareholders, respectively, and incorporated herein by reference.

In addition, the Energy Efficiency Act requires electric distribution companies to file with the Connecticut Energy Advisory Board (CEAB) an integrated resource plan (IRP) which includes an assessment of the state’s energy and capacity resources, including, but not limited to, conventional and renewable generating facilities, energy efficiency, load management, demand response, combined heat and power facilities, distributed generation and other emerging energy technologies to meet the projected requirements of their customers in a manner that minimizes the cost of such resources to customers over time and maximizes consumer benefits consistent with the state's environmental goals and standards. CL&P and UI filed a joint IRP with the CEAB on January 2, 2008. The CEAB may modify or accept the plan prior to filing it with the DPUC by May 1, 2008.

The Energy Efficiency Act also requires electric distribution companies to file proposals with the DPUC to build cost-of-service peaking generation facilities. CL&P filed a qualification submission with the DPUC on February 1, 2008, proposing two sites for peaking generation, and will file a detailed proposal on or about March 3, 2008. For further information, see "Legislative Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

On February 27, 2008, the DPUC issued a final decision in a docket examining the manner of operation and accuracy of CL&P's electric meters. While finding that the meters generally operated within industry standards, the DPUC imposed significant new testing, analytical and reporting requirements on CL&P. The DPUC also found that CL&P failed to be responsive to customer complaints by refusing meter tests or not allowing customers to speak with supervisors. The decision acknowledges recent corrective actions taken by CL&P but requires changes in numerous customer service practices. The decision also places substantial new tracking and reporting obligations on CL&P. The decision does not fine CL&P but holds that possibility open if CL&P fails to meet benchmarks to be established in this docket.

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases its energy requirements to serve its Standard Service and Supplier of Last Resort loads from a variety of competitive sources through periodic requests for proposals (RFPs). CL&P issues RFPs periodically for periods of up to three years to layer Standard Service full requirements supply contracts in order to mitigate market volatility for its residential and small and medium commercial and industrial customers. CL&P issues RFPs for Supplier of Last Resort service for larger commercial and industrial customers every three months. Currently, CL&P has in place contracts with various suppliers through 2010. The DPUC is evaluating whether it will implement any changes to the RFP process.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

Distribution (Including Regulated Generation)

PSNH is primarily engaged in the generation, purchase, transmission, delivery and sale of electricity to its residential, commercial and industrial customers. At December 31, 2007, PSNH furnished retail franchise electric service to approximately 491,000 retail customers in 211 cities and towns in New Hampshire. PSNH also owns and operates approximately 1,200 MW of electricity generation assets. Approximately 70 MW of those generation assets are hydroelectric units. Included among these generating assets is a 50 MW wood-burning generating unit in Portsmouth, New Hampshire, which was converted from a coal-burning unit and went into full operation in December 2006.

The following table shows the sources of 2007 electric franchise retail revenues based on categories of customers:


PSNH
Residential		44%
Commercial		40%
Industrial		15%
Other		1%
Total		100%

Rates

PSNH is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC) which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.

Default Energy Service (ES) Rates. PSNH’s ES rate recovers PSNH's generation and purchased power costs, including an ROE on PSNH's generation assets. PSNH files for approval of updated ES rates periodically with the NHPUC to ensure timely recovery of its costs. PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

On December 28, 2007, the NHPUC approved an increase in the ES rate to $0.0882 per kWh, effective January 1, 2008. Among other items, the new rate reflects an increase in PSNH’s authorized generation ROE to 9.81% effective January 1, 2008.

Under the terms of the order issued by the NHPUC approving PSNH’s new wood-burning generation plant (Northern Wood Power Project), which replaced one of the three 50 MW boiler units at the coal-fired Schiller Station, certain revenue, credits and cost avoidances (revenue sources) are shared between PSNH and its customers. These revenue sources include sales of renewable energy certificates (RECs) to other utilities, brokers, or suppliers, and production tax credits. In any given year, if the combination of revenue sources falls short of a stipulated revenue level, PSNH and its customers each share half of any deficiency, and if the combination exceeds the stipulated revenue level, PSNH and its customers each share half of any excess. The Northern Wood Power Project entered commercial operation on December 1, 2006, and revenue sources exceeded stipulated levels in 2007 due to its performance and favorable pricing in the Massachusetts market for the RECs. As a result, customers and shareholders will share equally a benefit of about $9.2 million of incremental revenues for 2007. A majority of PSNH’s share of these benefits will be recognized in 2008 when the 2007 RECs are delivered.

Although PSNH's customers are entitled to choose competitive energy suppliers, PSNH has experienced only a small amount of customer migration to date.

Delivery Service (DS) Rates. On May 30, 2006, PSNH filed a petition with the NHPUC requesting an increase in its DS rates. On May 25, 2007, the NHPUC approved a distribution and transmission rate case settlement agreement (PSNH rate settlement agreement) between PSNH, the NHPUC staff and the Office of Consumer Advocate. The PSNH rate settlement agreement provided for a $37.7 million annualized increase ($26.5 million estimated for distribution and $11.2 million estimated for transmission in base rates subject to tracking) that was effective on July 1, 2007, replacing a previous $24.5 million temporary distribution rate settlement increase that was effective on July 1, 2006. The $37.7 million includes a one-year revenue increase of approximately $9 million to recoup the difference between the temporary and the approved rates for the period July 1, 2006 through June 30, 2007. An additional delivery revenue increase of $3 million took effect on January 1, 2008 with a final rate decrease of approximately $9 million scheduled for July 1, 2008.

Transmission Cost Adjustment Mechanism. On June 1, 2007, PSNH filed a petition with the NHPUC seeking to establish a Transmission Cost Adjusting Mechanism (TCAM) rate consistent with the PSNH rate settlement agreement. The TCAM rate filing was amended on June 6, 2007 to reflect updates to wholesale transmission rates that were made available to PSNH after the initial June 1, 2007 filing. The NHPUC issued an order on June 29, 2007 approving a TCAM rate of $0.00752 per kWh for the period July 1, 2007 through June 30, 2008.

Stranded Cost Recovery Charge (SCRC). Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs. PSNH has financed a significant portion of its stranded costs through securitization by issuing rate reduction bonds secured by the right to recover these stranded costs from customers over time. It recovers the costs of these bonds through the SCRC rate. On an annual basis, PSNH files with the NHPUC an SCRC reconciliation filing for the previous year. For further information on PSNH rates, see "Regulatory

Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in our Annual Report to Shareholders which is incorporated herein by reference.

Coal Procurement Docket: During the second quarter of 2006, the NHPUC opened a docket to review PSNH's coal procurement and coal transportation policies and procedures. A consultant hired by the NHPUC conducted an investigation and made certain preliminary findings and recommendations. PSNH responded to the consultants report and consulted with the NHPUC Staff. As a result of those discussions, PSNH agreed to many of the recommendations made concerning the conduct of its coal procurement activities. There will be no material adverse financial impact on PSNH as a result of implementing the Staff's recommendations.

Sources and Availability of Electric Power Supply

During 2007, about 70% of PSNH load was met through its own generation and long-term power supply rate orders and contracts with third parties. The remaining 30% of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 2008 in a similar manner.

On May 11, 2007, New Hampshire Governor Lynch signed into law the "Renewable Energy Act," establishing renewable portfolio standards for electricity sold in the state, and ultimately requiring that 23.8% of the electricity sold to retail customers have direct ties to renewable sources by 2025. The renewable sourcing requirements begin in 2008 and increase each year to reach 23.8% by 2025. PSNH will be required to comply with these standards, which it plans to do primarily through the purchase of RECs or through Alternative Compliance Payments allowed under state law. PSNH expects that the additional costs incurred in meeting this new requirement will be recovered through PSNH’s energy service rates. For further information, see "Other Regulatory and Environmental Matters" in this Annual Report on Form 10-K.

WESTERN MASSACHUSETTS ELECTRIC COMPANY

Distribution

WMECO is engaged in the purchase, transmission, delivery and sale of electricity to residential, commercial and industrial customers. At December 31, 2007, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western third of Massachusetts. WMECO does not own any electricity generating facilities.

The following table shows the sources of 2007 electric franchise retail revenues based on categories of customers:


WMECO
Residential		56%
Commercial		32%
Industrial		11%
Other		1%
Total		100%

Rates

WMECO is subject to regulation by the Massachusetts Department of Public Utilities (formerly the Department of Telecommunications and Energy) (DPU), which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. WMECO's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to cover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under state law, all of WMECO's customers are now entitled to choose their energy suppliers, while retaining WMECO as their distribution company. WMECO purchases electric power for and passes through the cost to those customers who do not choose a competitive energy supplier (basic service). Basic service charges are adjusted and reconciled on an annual basis. Most of WMECO's residential and smaller customers have continued to buy their power from WMECO at basic service rates. A greater proportion of large commercial and business customers have opted for a competitive energy supplier. As of December 31, 2007, approximately 15,000 or 7% out of nearly 206,000 customers had elected this option, representing about 45% of the energy delivered by WMECO.

WMECO collects its transmission costs through a transmission adjustment clause. The DPU approved the tracking mechanism in January 2002, which provides for annual adjustments, thereby allowing WMECO to recover all of its retail transmission expenses on a timely basis.

WMECO has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred stranded costs. WMECO has financed a portion of its stranded costs through securitization by issuing rate reduction certificates secured by the right to recover stranded costs from customers over time. It is recovering the costs of securitization through rates.

Rate Case Settlement. WMECO implemented a $1 million rate increase on January 1, 2007 to reflect a distribution rate increase approved by the DPU in December 2006. An additional increase of $3 million became effective on January 1, 2008. Rates were also adjusted January 1, 2008 to include approved adjustments in various tracking mechanisms and new basic service contracts. For further information on WMECO rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

Sources and Availability of Electric Power Supply

As noted above, WMECO does not own any generation assets and purchases its energy requirements from a variety of competitive sources through periodic RFPs. For basic service power supply, WMECO issues RFPs periodically, consistent with DPU regulations. For 2008, WMECO entered into an agreements on May 15, 2007, to secure 50% of residential, small commercial and industrial, and street lighting loads for the July 1, 2007 through June 30, 2008 period, and on November 13, 2007 to secure power for half of its residential, small commercial and industrial, and street lighting loads for the January 1 through December 31, 2008 period. WMECO will issue an RFP in the second quarter of 2008 to secure the remaining 50% of its residential, small commercial and industrial, and street lighting loads for the July 1 through December 31, 2008 period and 50% of the load for January 1, 2009 through June 30, 2009. For its large commercial and industrial customers, WMECO entered into an agreement on November 13, 2007 to secure power for the first quarter of 2008 and an agreement to secure power for the second quarter 2008 on February 12, 2008. RFPs will be issued quarterly to address the balance of the year.

LICAP AND FCM DEVELOPMENT

On December 1, 2006 a FERC-approved Forward Capacity Market settlement agreement was implemented, and the payment of fixed compensation to generators began. Several parties challenged the FERC’s approval of the FCM settlement agreement and that challenge is pending in the Court of Appeals. The first forward capacity auction concluded in early February of 2008 for the capacity year of June of 2010 through May of 2011. The bidding reached the establishment minimum of $4.50 per kilowatt-month with 2,047MW of excess remaining capacity which means the effective capacity price will be $4.25 per kilowatt-month compared to the established price of $4.10 per kilowatt-month for the 12-month capacity period ending May 31, 2010. These costs are recoverable in all jurisdictions through the currently established rate structures.

For more information regarding CL&P, WMECO and PSNH state regulatory matters, see "Regulatory Developments and Rate Matters" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

REGULATED GAS DISTRIBUTION

Yankee Energy System, Inc. (Yankee) is the holding company of Yankee Gas and several immaterial non-utility subsidiaries, including NorConn Properties, Inc., which holds certain minor properties and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which was in the business of providing Yankee Gas customers and other energy end-users with financing primarily for energy equipment installations, but which is in the process of winding down its business operations.

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 200,000), and size of service territory (2,088 square miles). Total throughput (sales and transportation) for 2007 was 49.7 billion cubic feet (Bcf) compared with 45.2 Bcf in 2006. Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase gas from Yankee Gas. Yankee Gas also offers firm transportation service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel

on short notice. Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.

In 2007, Yankee Gas completed construction of a liquefied natural gas (LNG) facility in Waterbury, Connecticut at a total cost of approximately $108 million. The LNG facility is capable of storing the equivalent of 1.2 Bcf of natural gas. The facility was put in service in July 2007 and filling of the LNG tank was completed by the end of October 2007 to serve customers during the 2007-2008 heating season.

Yankee Gas earned $22.6 million on total gas operating revenues of approximately $514 million for 2007. The following table shows the sources of 2007 total gas operating revenues:


Yankee Gas
Residential		46%
Commercial		29%
Industrial		23%
Other		2%
Total		100%

For more information regarding Yankee Gas’s financial results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, "Financial Statements and Supplementary Data," which includes Note 16, "Segment Information," within the notes to the consolidated financial statements, contained within our Annual Report to Shareholders, which is incorporated into this Annual Report Form 10-K by reference.

Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC has limited oversight with respect to certain intrastate gas transportation that Yankee Gas provides. In addition, the FERC regulates the interstate pipelines serving Yankee Gas’s service territory.

Rates

Yankee Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.

On December 29, 2006, Yankee Gas filed an application with the DPUC requesting an increase to its distribution service rate primarily for the recovery of costs associated with its newly constructed LNG facility. The filing also included increases in operating and maintenance and depreciation costs as well as a requested ROE of 10.5%. Yankee Gas negotiated a settlement with the Connecticut Office of Consumer Counsel (OCC) and the DPUC’s Prosecutorial Division which resulted in an annualized increase of $22 million, or 4.2%, in Yankee Gas’s base rates, net of expected pipeline and commodity cost savings resulting primarily from completion of Yankee Gas’s LNG facility. The settlement included, among other things, the recovery of the costs of construction of its LNG facility, higher costs-of-service and an authorized ROE of 10.1%. Yankee Gas will return to ratepayers 100% of all earnings in excess of the allowed 10.1% ROE. The settlement also allows Yankee Gas to defer certain costs for future recovery associated with the Department of Transportation’s Office of Pipeline Safety regulations regarding pipeline integrity and improved pipeline safety. The DPUC approved the settlement on June 29, 2007 for rates effective July 1, 2007.

Yankee Gas recovers its cost of gas supplied to customers through a Purchased Gas Adjustment clause in its rate tariff. In 2005 and 2006, the DPUC issued decisions requiring an audit by an independent party of approximately $11 million in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005. The audit was concluded, and a final report was submitted to the DPUC. A DPUC hearing was held on October 9, 2007. Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for the audit period were appropriate and will be approved.

In 2007, in addition to the approximately $108 million capitalized for the LNG facility, Yankee Gas also capitalized $51.8 million related to reliability improvements, new customer connections and other initiatives.

REGULATED ELECTRIC TRANSMISSION

General

CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which they participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Operator (RTO) of the New England Transmission System since February 1, 2005. ISO-NE seeks to ensure the reliability of the system, administers the independent system operator tariff, subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which portion of our major transmission facilities are regionalized throughout New England.

Wholesale Rates

Wholesale transmission revenues are based on formula rates that are approved by the FERC. Most of our wholesale transmission revenues are collected under the FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes the Regional Network Service (RNS) and Local Network Service (LNS) rate schedules, among other things. The RNS rate, administered by ISO-NE and billed to all New England transmission owners, is reset on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The LNS rate, which we administer, is reset on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not covered under the RNS rate, including 50% of the costs of construction work in progress (CWIP) on our remaining southwest Connecticut transmission projects. Both the LNS and RNS rates are based on projected costs and the projected in-service dates of transmission projects and provide for annual true-ups to actual costs. The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e. RNS, rental, etc.), thereby ensuring that we recover all regional and local revenue requirements as described in Tariff No. 3.

FERC ROE Decision

On October 31, 2006, the FERC issued a decision (FERC ROE decision) on a request by New England transmission owners, including CL&P, PSNH and WMECO, for a number of incentives related to new transmission facilities. The FERC set a base rate of 10.2% and effective November 1, 2006, the FERC added a 70 basis point adjustment, bringing the going-forward base ROE to 10.9%. In addition, the FERC approved (i) a 50 basis point adder for RTO participation and (ii) a 100 basis point adder for all new transmission investment where the projects have been identified as necessary by the ISO-NE regional planning process for a potential ROE of 12.4%.

On a going forward basis, our transmission capital program is largely comprised of regional infrastructure that is included within the regional planning process and thus eligible for FERC incentive treatment. Approximately 90% of our projected $3 billion transmission capital program for the period 2008 through 2012 is expected to be in this category, and therefore is expected to earn at the ROE of 12.4%.

On November 30, 2006, the New England transmission owners jointly filed a rehearing request for an additional 30 basis points for the base ROE to correct what appears to be an error in the FERC's base ROE calculation. Additionally, several New England Public Utilities Commissions, Consumer Counsels and Municipals filed a rehearing request challenging the 70 basis point adjustment and the 100 basis point adder for new regional transmission investment. On December 29, 2006, FERC issued a tolling order stating that it accepted the various rehearing requests and intends to act on them. This order allows the regional transmission owners to collect tariffs per the FERC ROE decision, subject to refund. The order did not include an action date, and until FERC takes some action on the rehearing requests, parties cannot bring an appeal to court.

As a result of the FERC ROE decision, we recorded an estimated regulatory liability for refunds of $25.6 million as of December 31, 2006. During the first half of 2007, we completed the customer refunds that were calculated in accordance with the compliance filing required by the FERC ROE decision, and refunded approximately $23.9 million to regional, local and localized transmission customers. The $1.7 million positive pre-tax difference ($1 million after-tax) between the estimated regulatory liability recorded and the actual amount refunded was recognized in earnings in 2007.

Pursuant to the FERC ROE decision, the New England transmission owners submitted a compliance filing that calculated the refund amounts for transmission customers for the February 1, 2005 to October 31, 2006 time period. Subsequently, on July 26, 2007, the FERC issued an order disagreeing with the ROEs the transmission owners used in their refund calculations for the 15-month period between June 3, 2005 and September 3, 2006, rejected a portion of the compliance filing, and required another compliance filing within 30 days. On August 27, 2007, we filed, along with the other New England transmission owners a revised compliance filing which outlined the regional refund process to comply with the FERC’s July 26, 2007 order. In addition, the transmission owners filed a request for rehearing claiming that FERC improperly set the floor for refunds for the 15-month period from June 3, 2005 to September 3, 2006 based on the lower rates of the FERC ROE decision, rather than the last approved rates of the transmission owners. FERC denied this request on January 17, 2008, and the transmission owners have until March 17, 2008 to appeal, if they so choose.

The transmission segment of our regulated companies refunded approximately $2.2 million of revenues related to the July 26, 2007 FERC order (approximately $1.4 million after-tax) while the distribution segment received a net after-tax benefit of approximately $0.3 million as a result of these refunds. The refunds, net of benefits, totaling $1.1 million after-tax were recorded in 2007. For further information, see "Transmission Rate Matters and FERC Regulatory Issues" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

Other Rate Matters

On July 28, 2006, the FERC approved CL&P's proposal to allocate certain localized costs associated with the Bethel to Norwalk transmission project to all customers in Connecticut, as all of Connecticut will benefit from the reduction in congestion charges associated with the project. There are three load serving entities in Connecticut: CL&P, UI and the Connecticut Municipal Electric Energy Cooperative (CMEEC). These customers began to pay their allocated shares of the localized costs on a projected basis on June 1, 2006, subject to true-up based on actual costs. On December 26, 2006, FERC rejected a request by UI for rehearing of this decision. On February 23, 2007, UI appealed the FERC's orders to the D.C. Circuit Court of Appeals. On January 8, 2008, UI withdrew its appeal.

On November 1, 2007, we made a filing at FERC requesting recovery of deferred costs that we incurred as a result of our participation in the development, formation and startup of ISO-NE as the RTO for the New England region. We requested FERC’s approval to transfer the costs to a regulatory asset account and to amortize them over a three year period beginning January 1, 2008. On December 31, 2007, the FERC conditionally accepted our proposed rate recovery subject to refund and subject to a compliance filing. For the compliance filing, FERC requested that we demonstrate that the proposed accounting will not cause any greater economic harm to our customers than if we had filed earlier and that we provide the purpose and nature of our costs in relation to the formation of the RTO.

Transmission Projects

Our ongoing transmission projects currently consist of three major transmission projects in southwest Connecticut;

A 69-mile, 345 kilovolt (kV)/115 kV transmission project from Middletown to Norwalk, Connecticut. CL&P's portion of this project is estimated to cost approximately $1.05 billion. At February 20, 2008, CL&P's portion of this project was approximately 70% complete. As of December 31, 2007, CL&P had capitalized $593 million associated with this project. Although the project is scheduled to be completed by the end of 2009, construction of the project is currently ahead of schedule, and CL&P has reviewed the remaining work to determine whether it can be completed at an earlier date. As a result of this review, we now expect to complete this project in mid-2009.

A two-cable, nine-mile, 115 kV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October of 2006. This project is estimated to cost approximately $223 million. This project is scheduled to be completed by the end of 2008. At February 20, 2008, this project was approximately 73% complete. At December 31, 2007, CL&P had capitalized $133 million of associated costs.

The replacement of the 11-mile undersea 138 kV electric transmission cable between Connecticut and Northport, Long Island, New York. Permitting, contracting, and cable manufacturing for this project is complete. CL&P and the Long Island Power Authority (LIPA) each own approximately 50% of this line. CL&P's portion of the project is estimated to cost $72 million. Marine construction activities commenced in October of 2007 and we expect that the project will be placed in service in the second half of 2008. The previous cables were decommissioned in September 2007, and approximately 94% of the cables were removed as of December 31, 2007, including all portions located in Connecticut. Installation of the new cable began in early February 2008. At February 20, 2008, the project was approximately 71% complete. At December 31, 2007, CL&P had capitalized $45 million of associated costs, including the cost of the new cable which was delivered in the fourth quarter of 2007.

In addition, CL&P’s $335 million Bethel, Connecticut to Norwalk 345-kV transmission project, which entered service in late 2006, operated well in 2007 and reduced Connecticut congestion costs by approximately $150 million in its first full year in service.

In addition to our current transmission construction in southwest Connecticut, we continue to work with ISO-NE to refine the design criteria of our next series of major transmission projects: (i) the New England East-West 345 kV and 115 kV Overhead project (NEEWS Overhead project) and (ii) the 115 kV Springfield Underground Cables project (Springfield Underground Cables project).

The NEEWS Overhead project includes three 345 kV transmission upgrades that will collectively address the region's transmission needs and better connect the major east-west transmission interfaces in Southern New England: 1) the Greater Springfield 345 kV Reliability Project, 2) the Central Connecticut Reliability Project, and 3) the Interstate Reliability Project. A fourth upgrade, National Grid's Rhode Island Reliability Project, is also included in the NEEWS Overhead project. In early 2007, we entered into a formal agreement with National Grid to plan and permit these projects and expect the ISO-NE technical review process with respect to the NEEWS Overhead project to conclude by mid- to late- 2008. We will make the filing of the first project applications with the various state siting authorities shortly after receiving the technical approvals from ISO-NE. We continue to work with ISO-NE to ensure that the design of these projects balances needs and reliability, operational flexibility, and cost. At this time, we expect the siting process for the NEEWS Overhead project to be completed by 2010 and to complete construction in 2013. We have not yet updated our detailed estimate of the total cost for the NEEWS Overhead project, and the timing of expenditures is highly dependent upon receipt of technical and siting approvals.

The second major transmission project, the Springfield Underground Cables project, consists of a significant upgrade of the 115 kV electrical system around Springfield, Massachusetts to address thermal overload and voltage issues. WMECO received a favorable vote from the ISO-NE Reliability Committee regarding the project’s technical feasibility in December 2007, and WMECO filed the siting application immediately thereafter with the Massachusetts siting agencies. We expect the siting process to be completed in 2009 and expect WMECO to complete the project by the end of 2011.

Assuming that virtually all of the 345 kV portions of the NEEWS Overhead project are constructed overhead and on existing rights of way, we are maintaining our estimate of our share of the cost of the NEEWS Overhead project at approximately $1.05 billion. We are also maintaining our estimate of the cost of the Springfield Underground Cables project at approximately $350 million at this time. However, as we continue to review the designs of the NEEWS Overhead project and the Springfield Underground Cables project with ISO-NE over the coming months, we expect these figures to change. We anticipate that we will have additional information on the scope and costs of these projects by mid-2008.

We continue to review and analyze potential transmission solutions for New England’s environmental and operating challenges, particularly, meeting renewable portfolio standard and regional greenhouse gas initiative requirements, and improving reliability and fuel diversity. In December, 2007 we delivered a presentation describing a conceptual set of high voltage direct current projects and their potential economic and environmental benefits at ISO-New England’s Planning Advisory Committee meeting. We are continuing discussions with Canadian suppliers, New England transmission owners, New England state regulators and other key stakeholders to better understand the costs and benefits of new regional transmission solutions and the potential for a firm project proposal.

Transmission Rate Base

Under our FERC-approved tariffs, transmission projects enter rate base once they are placed in commercial operation. Additionally, 50% of our capital expenditures on each of our three major transmission projects still under construction in southwest Connecticut enter rate base during the construction period, with the remainder entering rate base once the projects are complete. At the end of 2007, our estimated transmission rate base was approximately $1.5 billion, including approximately $1.2 billion at CL&P, $175 million at PSNH and $80 million at WMECO. We forecast that our total transmission rate base will grow to approximately $3.9 billion by the end of 2012. This increase in transmission rate base is driven by the need to improve the capacity and reliability of our regulated transmission system.

A summary of projected year-end transmission rate base by regulated company is as follows (millions of dollars):


Company	2008	2009	2010	2011	2012
CL&P	$1,763	$2,168	$2,199	$2,515	$2,828
PSNH	295	306	367	371	458
WMECO	114	242	422	549	606
Totals	$2,172	$2,716	$2,988	$3,435	$3,892

For more information regarding Regulated Transmission matters, see "Transmission Rate Matters and FERC Regulatory Issues" and "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and

Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM

The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding the existing electric transmission and distribution system and natural gas distribution system. Our consolidated capital expenditures in 2007, including amounts incurred but not paid, cost of removal, allowance for funds used during construction and the capitalized portion of pension expense or income, totaled approximately $1.3 billion, almost all of which was expended by the regulated companies. The capital expenditures of these companies in 2008 are estimated to total approximately $1.3 billion. Of this amount, approximately $872 million is expected to be expended by CL&P, $275 million by PSNH, $85 million by WMECO and $56 million by Yankee Gas. This construction budget includes anticipated costs for all committed capital projects (i.e. generation, transmission, distribution, environmental compliance and others) and those reasonably expected to become committed projects in 2008. We expect to evaluate needs beyond 2008 in light of future developments, such as restructuring, industry consolidation, performance and other events. Increases in proposed distribution capital expenditures stems primarily from increasing labor and material costs and an aging infrastructure. The costs (both labor and material) that our regulated companies incur to construct and maintain their electric delivery systems have increased dramatically in recent years. These increases have been driven primarily by higher demand for commodities and electrical products, as well as increased demand for skilled labor. Our regulated companies have many major classes of equipment that are approaching or beyond their useful lives, such as old and obsolete distribution poles, underground primary cables and substation switchgear. Replacement of this equipment is extremely costly. Construction of the currently anticipated projects will require additional external debt financing at the subsidiary level and debt and equity financing at the NU Parent level.

CL&P’s transmission capital expenditures in 2007 totaled approximately $661 million. The increase in transmission segment capital expenditures in 2007 as compared with 2006 primarily relates to three major transmission projects under construction in southwest Connecticut: 1) the Middletown to Norwalk project, 2) the Glenbrook Cables project, and 3) the replacement of the underwater 138 kV cable between Connecticut and Long Island.

For 2008, CL&P projects transmission capital expenditures of approximately $538 million. During the period 2008 through 2012, CL&P plans to invest approximately $1.95 billion in transmission projects, including $571 million to complete the construction of its three southwest Connecticut projects.

In addition to its transmission projects, CL&P plans distribution capital expenditures to meet growth requirements and improve the reliability of its distribution system. In 2007, CL&P's distribution capital expenditures totaled approximately $283 million. Due to significant peak load growth in recent years, CL&P projects increasing distribution capital expenditures to approximately $334 million in 2008. CL&P plans to spend approximately $1.5 billion on distribution projects during the period 2008-2012. If all of the distribution and transmission projects are built as proposed, CL&P’s rate base for electric transmission is projected to increase from approximately $1.2 billion at the end of 2007 to approximately $2.8 billion by the end of 2012, and its rate base for distribution assets is projected to increase from approximately $1.9 billion to approximately $2.7 billion over the same period.

In 2007, PSNH's transmission capital expenditures totaled approximately $81 million, its distribution capital expenditures totaled $88 million and its generation capital expenditures totaled $35 million. For 2008, PSNH projects transmission capital expenditures of approximately $108 million, distribution capital expenditures of approximately $104 million and generation capital expenditures of approximately $63 million. The increase in distribution capital expenditures is mostly due to additional reliability expenditures, the new Cyber Security program and a number of major substation projects. The increase in generation capital expenditures is mostly due to the Merrimack 2 HP/IP and air heater tube replacement projects as well as higher expenditures for the Merrimack Scrubber project. During the period 2008-2012, PSNH plans to spend approximately $401 million on transmission projects and approximately $887 million on distribution and generation projects, including the installation of a wet scrubber to reduce mercury and sulfur emissions at its 440 MW coal-fired plant at Merrimack Station. If all of the distribution, generation and transmission projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from approximately $175 million at the end of 2007 to approximately $458 million by the end of 2012, and its rate base for distribution and generation assets is projected to increase from approximately $925 million to approximately $1.4 billion over the same period.

In 2007, WMECO's transmission capital expenditures totaled approximately $19 million and its distribution capital expenditures totaled approximately $34 million. In 2008, WMECO projects transmission capital expenditures of approximately $50 million and distribution capital expenditures of approximately $35 million. During the period 2008-2012, WMECO plans to spend approximately $648 million on transmission projects, with the bulk of that amount to be spent on the 115 kV Springfield Underground Cables project and the NEEWS 115 kV and 345 kV Overhead projects, and approximately $177 million on distribution projects. If all of the distribution and transmission

projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $81 million at the end of 2007 to approximately $606 million by the end of 2012 and its rate base for distribution assets is projected to increase from approximately $372 million to approximately $503 million over the same period.

In 2007, Yankee Gas’s capital expenditures totaled approximately $64 million, approximately $12 million of which was for the construction of its LNG facility. The facility was filled with LNG by the end of October 2007 to serve customers during the 2007/2008 heating season. The LNG facility was placed in service in July 2007 on budget with a final cost of approximately $108 million. In 2007, Yankee Gas also spent $23 million on its reliability improvement program, $20 million on connecting new customers, and $9 million on other initiatives, including meters and information technology systems. For 2008, Yankee Gas projects total capital expenditures of approximately $56 million. During the period 2008-2012, Yankee Gas plans on making approximately $305 million of capital expenditures. If all of Yankee Gas’s projects are built as proposed, Yankee Gas’s investment in its regulated assets is projected to increase from approximately $666 million at the end of 2007 to approximately $806 million by the end of 2012.

Strategic Initiatives: We are also evaluating certain development projects that would benefit our customers, such as new regulated generating facilities, investments in AMI systems to provide time-of-use rates to our customers, and transmission projects to better interconnect new renewable generation in northern New England and Canada with southern New England, as well as interconnections within New Hampshire. The estimated capital expenditures and projected rate base amounts discussed above do not include expenditures related to these initiatives.

For more information regarding NU and its subsidiaries' construction and capital improvement programs, see "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

STATUS OF EXIT FROM COMPETITIVE ENERGY BUSINESSES

Since 2005, we have been in the process of exiting our competitive energy businesses and are now focusing exclusively on our regulated businesses. At December 31, 2007, our competitive businesses consisted solely of (i) Select Energy’s few remaining wholesale marketing contracts and (ii) NU Enterprises’ remaining energy services business, consisting of NGS, Boulos and the Connecticut division of SECI.

Four of the five remaining Select Energy wholesale sales contracts that were in the PJM power pool at the beginning of 2007 expired on May 31, 2007. The remaining PJM wholesale sales contract will expire on May 31, 2008. Select Energy’s wholesale contract with The New York Municipal Power Agency (NYMPA) expires in 2013. In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a long-term non-derivative contract to purchase the output of a certain generating facility in New England through 2012.

Also in 2007, the remaining contracts of SECI and the former Woods Electrical Co., Inc. wound down. For more information regarding the exit of the competitive businesses, see "NU Enterprises Divestitures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements, contained within our Annual Report to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

FINANCING

We paid dividends on our common shares totaling $121 million in 2007, compared to $112.7 million in 2006, reflecting increases in the quarterly dividend amount that were effective in the third quarters of 2006 and 2007.

Our total debt, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including rate reduction bonds or certificates, was approximately $3.7 billion as of December 31, 2007.

During 2007, the regulated companies issued the following debt:

On March 27, 2007, CL&P issued $150 million of its 10-year first and refunding mortgage bonds carrying a coupon rate of 5.375%, and $150 million of its 30-year first and refunding mortgage bonds carrying a coupon rate of 5.75%.

On August 17, 2007, WMECO issued $40 million of its 30-year unsecured senior notes with a coupon rate of 6.7%.

On September 17, 2007, CL&P issued $100 million of its 10-year first and refunding mortgage bonds carrying a coupon rate of 5.75%, and $100 million of its 30-year first and refunding mortgage bonds carrying a coupon rate of 6.375%.

On September 24, 2007, PSNH issued $70 million of its 10-year first mortgage bonds with a coupon rate of 6.15%.

At December 31, 2007, NU parent maintained a revolving credit facility of $500 million, and the regulated companies maintained a joint revolving credit facility of $400 million, both of which expire on November 6, 2010. At December 31, 2007, there were $42 million in borrowings and $27 million in letters of credit outstanding under the NU parent credit facility. There were $45 million of long-term borrowings by Yankee Gas outstanding under the regulated companies’ facility at December 31, 2007. In addition, there were $10 million and $27 million in short-term borrowings by PSNH and Yankee Gas, respectively, outstanding under the regulated companies’ facility at December 31, 2007.

In addition, CL&P has access to funds under an arrangement with its subsidiary, CL&P Receivables Corporation (CRC). CRC has an agreement with CL&P to purchase up to $100 million of an undivided interest in CL&P's accounts receivables and unbilled revenues, which CRC sells to a highly rated financial institution on a limited recourse basis. CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables. At December 31, 2007, CL&P had sold $20 million under this facility.

Financial Covenants in Credit Facilities. Under their revolving credit facility agreements, each of NU, CL&P, WMECO, PSNH and Yankee Gas must maintain a ratio of consolidated debt to total capitalization of no more than 65%. At December 31, 2007, NU, CL&P, WMECO, PSNH, and Yankee Gas were, and are expected to remain, in compliance with this ratio.

For more information regarding NU and its subsidiaries' financing, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to long-term debt, short-term debt, leases and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements, and "Liquidity" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which are incorporated into this Annual Report on Form 10-K by reference.

NUCLEAR DECOMMISSIONING

General

CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of three regional nuclear companies, Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC) and Yankee Atomic Electric Company (YAEC) (the Yankee Companies). Until recently, each Yankee Company owned a single nuclear generating unit –the Connecticut Yankee nuclear unit, the Maine Yankee nuclear unit, and the Yankee Rowe nuclear unit. The Yankee Companies have completed the physical decommissioning of their respective facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates. The stock ownership percentages of CL&P, PSNH and WMECO in the Yankee Companies are set forth below:


	CL&P	PSNH	WMECO
Connecticut Yankee Atomic Power Company	34.5%	5.0%	9.5%
Maine Yankee Atomic Power Company	12.0%	5.0%	3.0%
Yankee Atomic Electric Company	24.5%	7.0%	7.0%

Our share of the obligations to support the Yankee Companies under FERC-approved rules is the same as the ownership percentages above.

For more information regarding decommissioning and nuclear assets, see "Deferred Contractual Obligations" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," within our Annual Report to Shareholders, which is incorporated into this Annual report on Form 10-K by reference.

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including the FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the DPUC having jurisdiction over CL&P and Yankee Gas, the NHPUC having jurisdiction over PSNH, and the DPU having jurisdiction over WMECO.

Environmental Regulation

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, our major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. Compliance with increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.

Water Quality Requirements

The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of obtaining or renewing all required NPDES or state discharge permits in effect for our facilities. Compliance with NPDES and state discharge permits has necessitated substantial expenditures and may require further significant expenditures, which are difficult to estimate, because of additional requirements or restrictions that could be imposed in the future, including requirements related to Sections 316(a) and 316(b) of the Clean Water Act for facilities owned by PSNH.

Air Quality Requirements

The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO₂) and nitrogen oxide (NO_X) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included.

In New Hampshire, the Multiple Pollutant Reduction Program was signed into law in May 2002. Under this law, NO_X, SO₂ and Carbon Dioxide (CO₂) emission are capped for current compliance beginning in 2007. A law was passed during the 2006 legislative session requiring reductions in emissions of mercury from coal-fired plants, including those owned by PSNH. The law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions (with the co-benefit of reductions in SO₂ emissions as well) at Merrimack Station no later than July 1, 2013. PSNH currently anticipates that compliance with this law will cost $250 million, but this amount has the potential to increase materially as the project is undertaken, primarily as a result of changes in commodity prices and labor costs.

The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by a group of northeastern states, including Massachusetts, New Hampshire and Connecticut, to develop a regional program for stabilizing and reducing CO₂ emissions from fossil fuel-fired electric generators. This initiative proposes to stabilize CO₂ emissions at current levels and require a 10% reduction from the initial 2009 permitted emissions levels by 2018. Each signatory state committed to propose for approval legislative and/or regulatory mechanisms to implement the program. The Connecticut Department of Environmental Protection (CDEP) released draft RGGI regulations on December 28, 2007 and had a public hearing on February 8, 2008. The CDEP plans to have these rules finalized by May 2008 and to participate in a proposed open regional auction of CO₂ allowances in June 2008. Connecticut has proposed an auction of 91% of allocated CO₂allowances with the remainder set aside for certain clean energy projects. Connecticut has proposed the first compliance period for affected facilities to begin on January 1, 2009. Although neither CL&P nor Yankee Gas currently have any facilities subject to the RGGI program, CL&P expects the cost of purchased energy supply to increase due to RGGI requirements. NU Enterprises manages a facility in Connecticut under a non-derivative contract which will likely be required to purchase CO₂ allowances. Massachusetts Department of Environmental Protection and Division of Energy Resources released their draft RGGI regulations on August 10, 2007. The final rule is expected in early 2008 and Massachusetts also plans to participate in the June 2008 regional auction. Although WMECO has no facilities that would be subject to this rule, it also expects the cost of purchased energy to increase. PSNH is the only one of our regulated companies that currently owns any generation assets that could be subject to the RGGI standards.

In New Hampshire, draft legislation has been proposed during this 2008 session that is consistent with the RGGI initiative. However, at this time because the draft legislation has not yet been finalized and because the cost of CO₂ allowances under RGGI cannot be identified with any certainty, we are unable to determine the actual cost of RGGI and its impact on customer rates.

On May 11, 2007, New Hampshire adopted renewable portfolio standards for electricity sold in the state which ultimately requires that 23.8% of the electricity sold to retail customers have direct ties to renewable sources by 2025. The renewable sourcing requirements begin in 2008 and increase each year to reach 23.8% by 2025. PSNH will be required to comply with these standards. We expect that the additional costs incurred to meet this new requirement will be recovered through PSNH’s energy service rates.

In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.

Hazardous Materials Regulations

Prior to the last quarter of the 20^th century when environmental best practices and laws were implemented, residues from operations were often disposed of by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability, and continue to evaluate the environmental impact of our former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on us for such past disposal. At December 31, 2007, the liability recorded by us for our estimable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $25.8 million, representing 53 liabilities. All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable. These costs could be significantly higher if additional remedial actions become necessary or when additional information as to the extent of contamination becomes available.

The most significant liabilities currently relate to future clean up costs at former manufactured gas plant (MGP) facilities. These facilities were owned and operated by predecessor companies to us from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We, through our subsidiaries, currently have partial or full ownership responsibilities at 28 former MGP sites. Of our total recorded liabilities of $25.8 million, a reserve of approximately $23.6 million has been established to address future investigation and/or remediation costs at MGP sites. In addition, remediation has been conducted at a coal tar contaminated river site in Massachusetts that is at least partially the responsibility of Holyoke Water Power Company (HWP), a subsidiary of NU, which previously owned generating assets. The cost to clean up that contamination may be more significant than currently estimated, but the level and extent of contamination remains unknown. Any and all exposure related to this site is not subject to ratepayer recovery. An increase to the environmental reserve for this site would be recorded in earnings in future periods and may be material.

In the past, we or our subsidiaries have received other claims from government agencies and third parties for the cost of remediating sites not currently owned by us but affected by our past disposal activities and may receive additional such claims in the future. We expect that the costs of resolving claims for remediating sites about which we have been notified will not be material, but we cannot estimate the costs with respect to sites about which we have not been notified.

For further information on environmental liabilities, see Note 8B, "Commitments and Contingencies - Environmental Matters" contained within NU's 2007 Annual Report to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

Electric and Magnetic Fields

For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.

We have closely monitored research and government policy developments for many years and will continue to do so. In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.

FERC Hydroelectric Project Licensing

New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.

PSNH owns nine hydroelectric generating stations with an aggregate of approximately 66.3 MW of capacity, with a current claimed capability representing winter rates, of approximately 69.5 MW. Of these nine plants, eight are licensed by the FERC under long-term licenses that expire on varying dates from 2009 through 2036. As a licensee under the Federal Power Act (FPA), PSNH and its licensed hydroelectric projects are subject to conditions set forth in the FPA and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.

FERC hydroelectric project licenses expire periodically and the generating facilities must be relicensed at such times. A new FERC license for PSNH’s Merrimack River Hydroelectric Project, which consists of the Amoskeag, Hooksett and Garvins Falls generating stations, was issued on May 18, 2007. PSNH's Canaan Hydroelectric Project is currently in FERC relicensing proceedings. The license for the Canaan Hydroelectric Project expires in 2009.

Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision which expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.

At this time, it appears unlikely that the FERC will order decommissioning of PSNH's hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked. However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics. Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.

EMPLOYEES

As of December 31, 2007, we employed a total of 5,869 employees, excluding temporary employees, of which 1,825 were employed by CL&P, 1,210 by PSNH, 337 by WMECO, 393 by Yankee Gas and 1,954 were employed by Northeast Utilities Service Company (NUSCO).

Approximately 2,217 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are covered by 11 union agreements.

INTERNET INFORMATION

Our website address is www.nu.com. We make available through our website a link to the SEC's EDGAR site, at which site NU's, CL&P's, WMECO's and PSNH's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037.

Item 1A.

Risk Factors

We are subject to a variety of significant risks in addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" in Item 1, "Business," above. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.

The infrastructure of our transmission and distribution system may not operate as expected, and could require additional unplanned expense which could adversely affect our earnings.

Our ability to manage operational risk with respect to our transmission and distribution systems is critical to the financial performance of our business. Our transmission and distribution businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age), accidents and labor disputes. The costs (both labor and material) that our regulated companies incur to construct and maintain their electric delivery systems have increased in recent years. These increases have been driven primarily by higher demand for commodities and electrical products, as well as increased demand for skilled labor. A significant percentage of our regulated company equipment is nearing or at the end of its life cycle, such as old and obsolete distribution poles, underground primary cables and substation switchgear. The failure of our transmission and distributions systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in expenses, including higher maintenance costs. Any such costs which may not be recoverable from our ratepayers would have an adverse effect on our earnings.

Changes in regulatory or legislative policy, difficulties in obtaining siting, design or other approvals, global demand for critical resources, or environmental or other concerns, or construction of new generation may delay completion of or displace our transmission projects or adversely affect our ability to recover our investments or result in lower than expected rates of return.

The successful implementation of our transmission construction plans is subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact our ability to meet our construction schedule and/or require us to incur additional expenses and may adversely affect our ability to achieve forecast levels of revenues. In addition, difficulties in obtaining required approvals for construction, or increased cost of and difficulty in obtaining critical resources as a result of global or domestic demand for such resources could cause delays in our construction schedule and may adversely affect our ability to achieve forecasted earnings.

The regulatory approval process for our planned transmission projects encompasses an extensive permitting, design and technical approval process. Various factors could result in increased cost estimates and delayed construction. These include environmental and community concerns and design and siting issues. Recoverability of all such investments in rates may be subject to prudence review at the FERC at the time such projects are placed in service. While we believe that all such expenses have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.

In addition, to the extent that new generation facilities are proposed or built to address the region’s energy needs, the need for our planned transmission projects may be delayed or displaced, which could result in reduced transmission capital investments, reduced earnings, and limit future growth prospects.

The currently planned transmission projects are expected to help alleviate identified reliability issues and to help reduce customers' costs. However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system and supply interruptions or blackouts may occur which could have an adverse effect on our earnings.

The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base before completion. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.

Increases in electric and gas prices and focus on conservation and self-generation by customers and changes in legislative and regulatory policy may adversely impact our business.

The nation's economy has been affected by significant increases in energy prices, particularly fossil fuels. The impact of these increases has led to increased electricity and natural gas prices for our customers, which has increased the focus on conservation, energy efficiency and self-generation on the part of customers and on legislative and regulatory policies. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.

In addition, Connecticut, New Hampshire and Massachusetts have each announced policies aimed at increased energy efficiency and conservation. In connection with such policies, all three states have opened proceedings to investigate revenue decoupling as a mechanism to align the interests of customers and utilities relative to conservation. In Connecticut, the DPUC authorized decoupling via a rate design that is intended to recover proportionately greater distribution revenue through the fixed Customer and Demand charges, and proportionately less distribution revenue through the per kWh charges. At this time it is uncertain what mechanisms will ultimately be adopted by New Hampshire and Massachusetts and what impact these decoupling mechanisms will have on our companies.

Changes in regulatory policy may adversely affect our transmission franchise rights or facilitate competition for construction of large-scale transmission projects, which could adversely affect our earnings.

We have undertaken a substantial transmission capital investment program and expect to invest approximately $3 billion in regulated electric transmission infrastructure from 2008 through 2012.

Although our public utility subsidiaries have exclusive franchise rights for transmission facilities in our service area, the demand for improved transmission reliability could result in changes in federal or state regulatory or legislative policy that could cause us to lose the exclusivity of our franchises or allow other companies to compete with us for transmission construction opportunities. Such a change in policy could result in reduced transmission capital investments, reduce earnings, and limit future growth prospects.

Changes in regulatory and/or legislative policy could negatively impact regional transmission cost allocation rules.

The existing New England Transmission tariff allocates the costs of transmission investment that provide regional benefits to all customers in New England. As new investment in regional transmission infrastructure occurs in any one state, there is a sharing of these regional costs across all of New England. This regional cost allocation is contractually agreed to remain in place until 2010 by the Transmission Operations Agreement signed by all of the New England transmission owning utilities but can be changed with the approval of a majority of the transmission owning utilities thereafter. After 2010, certain changes to the terms of the Transmission Operations Agreement could have adverse effects on our distribution companies' local rates. We are working to retain the existing regional cost allocation treatment but cannot predict the actions of the states or utilities in the region.

Changes in regulatory or legislative policy could jeopardize our full recovery of costs incurred by our distribution companies.

Under state law, our utility companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval. There is no assurance that these state commissions will approve the recovery of all costs prudently incurred by our regulated companies, such as for operation and maintenance, construction, as well as a return on investment on their respective regulated assets. Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our cash flows and results of operations.

In addition, CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis. CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DPU, respectively. While both regulatory agencies have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.

The energy requirements for PSNH are currently met primarily through PSNH's generation resources or fixed-price forward purchase contracts. PSNH’s remaining energy needs are met primarily through spot market or bilateral energy purchases. Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to meet requirements. PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC. We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.

The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial condition and results of operations.

Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We are developing strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.

Grid disturbances, severe weather, or acts of war or terrorism could negatively impact our business.

Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, or terrorist action) on an interconnected system or the actions of another utility. In addition, we are subject to the risk that acts of war or terrorism could negatively impact the operation of our system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial. The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.

A negative change in NU's credit ratings could require NU parent to post cash collateral and affect our ability to obtain financing.

NU parent’s senior unsecured debt ratings by Moody's Investors Service, Standard & Poor's, Inc. and Fitch Ratings are currently Baa2, BBB- and BBB, respectively, with stable outlooks. Were any of these ratings to decline to non-investment grade level, Select Energy could be asked to provide, as of December 31, 2007, collateral or letters of credit in the amount of $70.4 million to unaffiliated counterparties and collateral or letters of credit in the amount of $23.4 million to several independent system operators and unaffiliated local distribution companies (LDCs) under agreements largely guaranteed by NU parent. While our credit facilities are sufficient in amounts that would be adequate to meet cash calls at that level, our ability to meet any future cash calls would depend on our liquidity and access to bank lines and the capital markets at such time.

We expect to obtain the liquidity needed for our capital programs through bank borrowings, the issuance of long-term debt at the subsidiary level and debt and equity financing at the NU parent level. While we are reasonably confident these funds will be available on a timely basis and on reasonable terms, failure to obtain such financing could constrain our ability to finance regulated capital projects. In addition, any ratings downgrade of our securities or those of our subsidiaries, or any negative impacts on the credit market, generally, could negatively impact the cost or availability of capital.

Changes in wholesale electric sales could require Select Energy to acquire or sell additional electricity on unfavorable terms.

Select Energy's remaining wholesale sales contracts provide electricity to full requirements customers, including a regulated LDC and a municipal electric company. Select Energy provides a portion of the customer's electricity requirements. The volumes sold under these contracts vary based on the usage of the underlying retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as economic activity and weather. The varying sales volumes may differ from the supply volumes that Select Energy expected to utilize from electricity purchase contracts. Differences between actual sales volumes and supply volumes may require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions which change due to weather, plant availability, transmission congestion, and input fuel costs. The purchase of additional electricity at high prices or sale of excess electricity at low prices could negatively impact Select Energy's cost to serve the contracts.

We are subject to litigation which could result in large cash judgments against us.

We are engaged in litigation that could result in the imposition of large cash judgments against us. This litigation includes a civil lawsuit between us and Consolidated Edison, Inc. (Con Edison) relating to our October 13, 1999 Agreement and Plan of Merger.

We may also be subject to future litigation based on asserted or unasserted claims and cannot predict the outcome of any of these proceedings. Adverse outcomes in existing or future litigation could result in the imposition of substantial cash damage awards against us.

Further information regarding these legal proceedings, as well as other matters, is set forth in Item 3, "Legal Proceedings."

Costs of compliance with environmental regulations may increase and have an adverse effect on our business and results of operations.

Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate, among other things, air emissions, water discharges and the management of hazardous and solid waste. In particular, more stringent regulations of carbon dioxide and mercury emissions have been proposed in the various New England states in which we operate. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and results of operations, financial position and cash flows.

In addition, global climate change issues have received an increased focus on the federal and state government levels which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations. Although we would expect that any costs of these rules and regulations would be recovered from ratepayers, the impact of these rules and regulations on energy use by ratepayers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.

Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs which may not be fully recoverable in distribution company rates for generation. The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1, "Business - Other Regulatory and Environmental Matters - Environmental Regulation."

Item 1B.

Unresolved Staff Comments

We do not have any unresolved SEC staff comments.

Item 2.

Properties

Transmission and Distribution System

At December 31, 2007, our electric operating subsidiaries owned 196 transmission and 267 distribution substations that had an aggregate transformer capacity of 28,282,150 kilovolt amperes (kVa) and 2,253,520 kVa, respectively; 3,091 circuit miles of overhead transmission lines ranging from 69 KV to 345 KV, and 242 cable miles of underground transmission lines ranging from 69 KV to 345 KV; 34,760 pole miles of overhead and 2,817 conduit bank miles of underground distribution lines; and 532,416 underground and overhead line transformers in service with an aggregate capacity of 35,810,412 kVa.

Electric Generating Plants

As of December 31, 2007, PSNH owned the following electric generating plants:


Type of Plant	Number of Units	Year Installed	Claimed Capability* (kilowatts)

Total - Fossil-Steam Plants	(7 units)	1952-78	994,845
Total - Hydro-Conventional	(20 units)	1917-83	70,329
Total - Internal Combustion	(5 units)	1968-70	102,961

Total PSNH Generating Plant	(32 units)		1,168,135

*Claimed capability represents winter ratings as of December 31, 2007. The nameplate capacity of the generating plants is approximately 1,200 MW.

Neither CL&P nor WMECO owned any electric generating plants during 2007.

Yankee Gas

At December 31, 2007, Yankee Gas owned 27 gate stations, approximately 270 district regulator stations and 3,200 miles of main gas pipelines. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut as well as propane facilities in Danbury, Kensington and Vernon, Connecticut.

Franchises

CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.

In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distribution company from owning or operating generation assets. However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs. In addition, Section 83 of Public Act 07-242, "An Act Concerning Electricity and Energy Efficiency" states that if an existing electric generating plant located in Connecticut is offered for sale, then an electric distribution company, such as CL&P, would be eligible to purchase the generation plant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is in the public interest.

PSNH. The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.

In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The distribution and transmission franchises of PSNH include the power of eminent domain.

WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.

The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO. The Department of Telecommunications and Energy subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.

Holyoke Water and Power Company and Holyoke Power and Electric Company. HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed not to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and to amend the charters of HWP and HP&E to reflect that limitation.

The two companies have locations in the public highways for their transmission lines. Such locations are granted pursuant to the laws of Massachusetts by the Massachusetts Department of Public Works or by local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. HP&E has no retail service territory area and sells electric power exclusively at wholesale.

Yankee Gas. Yankee Gas directly and from its predecessors in interest holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility. Yankee Gas’s franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas’s franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.

Item 3.

Legal Proceedings

Consolidated Edison, Inc. v. NU - Merger Litigation

On March 5, 2001, Con Edison advised us that it was unwilling to close its merger with us on the terms set forth in our 1999 merger agreement (the Merger Agreement). On March 6, 2001, Con Edison filed suit in federal court in New York City seeking a declaratory judgment that we had suffered a material adverse change, as defined in the Merger Agreement, and that Con Edison was therefore excused from performing its obligations under the merger agreement. On March 12, 2001, we filed suit against Con Edison seeking to recover the merger premium, which totaled over $1 billion, for the benefit of our shareholders. On May 11, 2001, Con Edison filed an amended complaint seeking, in addition to the relief in its original complaint, an award of money damages of at least $314 million to compensate it for what it claims is the portion of the projected synergy savings that would have inured to the benefit of former Con Edison shareholders if the merger had been consummated and the estimated savings had been realized. Con Edison also sought to recover its merger related expenses, which it claims were approximately $32 million.

On October 12, 2005, the United States Court of Appeals for the Second Circuit issued a decision concluding that our shareholders did not have the right to sue Con Edison for the merger premium as a result of its alleged breach of the Merger Agreement. The ruling left intact the remaining claims between us and Con Edison for breach of contract, which include our claim for recovery of costs and expenses of approximately $27 million, and Con Edison's claim for its alleged synergy damages plus expenses of $32 million. Any award of damages would also include prejudgment interest on the amount of damages awarded from the date of the filing of the claim.

On January 31, 2008, the trial judge denied a series of motions by both us and Con Edison that had been pending for more than one year, including our motion for an order dismissing Con Edison's synergy damage claim and ordered the parties to be trial ready on four days' notice beginning March 21, 2008.

It is not possible to predict either the outcome of this matter or its ultimate effect on us.

NRG Bankruptcy

On May 14, 2003, NRG and certain of its affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). The filing affects relationships between various NU companies and the NRG companies, as follows:

A. Station Service

NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants (approximately $28 million, including late charges). The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states (i.e., the DPUC) have jurisdiction over the delivery of power to end users even where power is not delivered via distribution facilities. NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002 decision. Prior to the issuance of a decision by the DPUC, NRG filed a petition under Chapter 11 of the U.S. Bankruptcy Code, staying any further action by the DPUC. On December 17, 2003, the DPUC affirmatively stated that CL&P had been appropriately administering its station service rates. On January 8, 2008, CL&P and NRG filed a confidential proposed settlement with the DPUC, which would settle the competing claims. On January 28, 2008, the DPUC issued a final decision in CL&P’s rate case proceeding in which it also approved the confidential settlement between CL&P and NRG. CL&P and NRG signed the settlement agreement, which did not, and is not expected to, have a material adverse effect on CL&P, in February 2008.

B. Yankee Gas

On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT), was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project. Based on NRG's statement that it expected that Yankee Gas would draw on a $16 million letter of credit (LOC), Yankee Gas drew down the full amount of the LOC. On November 12, 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement), and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down the $16 million LOC. In April 2003, Yankee Gas filed its answer to MGT's complaint and asserted a counterclaim to recover its losses arising out of MGT's termination of the MGT Agreement. Yankee Gas and NRG signed a confidential settlement agreement which settled the competing claims in February 2008. The settlement did not, and is not expected to have a material adverse effect on Yankee Gas.

C. Congestion Charges

On August 5, 2002, CL&P withheld the past due congestion charges from its payment to NRG pursuant to contractual provisions allowing the withholding of disputed sums. CL&P continued to withhold congestion charges from its monthly payments to NRG, through March 1, 2003, and at present is withholding approximately $28 million. On November 28, 2001, CL&P filed a complaint against NRG in Connecticut Superior Court alleging breach of contract arising from the failure of NRG to pay approximately $29.6 million of socialized congestion charges. The case was removed to U.S. District Court for the District of Connecticut. NRG filed a counterclaim seeking recovery of all amounts CL&P has withheld. The court granted CL&P's motion for summary judgment and entered judgment in CL&P’s favor on all counts on July 25, 2007.

Yankee Companies v. U.S. Department of Energy

The Yankee Companies commenced litigation in 1998 against the United States Department of Energy (DOE) charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers. The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.

In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. The Yankee Companies had claimed actual damages for the same period as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million. The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE is established in the Yankee Companies' FERC-approved rate settlement agreement, although implementation will be subject to final determination of FERC. CL&P, PSNH and WMECO expect to pass any recovery onto their customers, therefore, no earnings impact is expected to result. In December 2006, the DOE appealed the decision, and the Yankee Companies filed cross-appeals. The appeal is expected to be argued in 2008 with a decision from the Court of Appeals to follow. The application of any damages which are ultimately recovered to benefit customers is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.

The Court of Federal Claims, following precedent set in another case, did not award the Yankee Companies future damages covering the period beyond the 2001/2002 damages award dates. In December 2007, the Yankee Companies filed a second round of lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001/2002.

Connecticut MGP Cost Recovery

On August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) of Pennsylvania for past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut. The NU Companies alleged that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests. Investigations and remediation expenditures at the sites to date total over $20 million, and projected potential remediation costs for all sites, based on litigation modeling assumptions, could total as much as $232 million. At this point, we are unable to estimate the potential costs associated with this matter.

In September 2006, the NU Companies filed a complaint against UGI in the U.S. District Court for the District of Connecticut seeking a fair and equitable contribution for the actual and anticipated remediation costs related to the former MGP operations. Discovery is scheduled through July 2008.

Dominion Nuclear-Station Service

On July 24, 2006, Dominion Nuclear Connecticut, Inc. (DNCI) filed a complaint at FERC, claiming that, because as of December 1, 2005, DNCI sought to "self-supply" its station service power through the ISO-NE settlement system rather than from CL&P as a Transitional Standard Service retail customer, it is not required to buy retail delivery service for that power. On August 14, 2006, CL&P answered the complaint, supported by the Connecticut DPUC, OCC and the AG.

On September 22, 2006, FERC issued an order finding that CL&P is not authorized to impose local distribution charges for station power delivery service on DNCI, and directed CL&P to cease charging DNCI retroactive to December 1, 2005. Since that date, DNCI has withheld approximately $1.7 million (including interest). CL&P sought rehearing and clarification on October 23, 2006. On May 27, 2007 FERC denied CL&P’s rehearing and clarification request stating that CL&P is not authorized to charge Dominion local distribution charges to deliver station service to Millstone through transmission lines. On January 28, 2008, the DPUC issued a final decision in CL&P’s rate case proceeding, which essentially reimburses CL&P for its net station service receivable for Dominion.

Other Legal Proceedings

The following sections of Item 1, "Business" discuss additional legal proceedings: See "Regulated Electric Distribution," "Regulated Gas Operations," and "Regulated Electric Transmission" for information about various state restructuring and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "Nuclear Decommissioning" for information related to high-level nuclear waste; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, "Risk Factors" for general information about several significant risks.

Executive Officers of the Registrant

This information is provided by NU in reliance on General Instruction G of Form 10-K.

Name

Age

Business Experience During Past 5 Years

Gregory B. Butler

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO, subsidiaries of NU, since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.

Peter J. Clarke

Vice President of Shared Services of NUSCO, a subsidiary of NU, since January 1, 2008, and performs policy-making functions for NU. Previously Vice President - Customer Operations of CL&P and Yankee Gas Services Company from July 1, 2006 to December 31, 2007; Vice President - Customer Operations and Relations of CL&P from January 17, 2005 to June 30, 2006; and Director - System Projects of CL&P from March 11, 2002 to January 16, 2005.

Cheryl W. Grisé

Executive Vice President of NU from December 1, 2005 to July 1, 2007; Chief Executive Officer of CL&P, PSNH and WMECO from September 10, 2002 to January 15, 2007, a Director of CL&P from May 1, 2001 to January 15, 2007, of PSNH from May 14, 2001 to January 15, 2007 and of WMECO from June 2001 to January 15, 2007; previously President - Utility Group of NU from May 2001 to December 1, 2005.

Jean M. LaVecchia

Vice President - Human Resources of NUSCO, a subsidiary of NU, since June 30, 2005, and performs policy-making functions for NU; also a Director of Northeast Utilities Foundation since January 30, 2007. Previously Vice President - Human Resources and Environmental Services from May 1, 2001 to June 30, 2005. Performs policy-making functions for NU.

David R. McHale

Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO since January 1, 2005 and a Director of PSNH and WMECO since January 1, 2005 and CL&P since January 15, 2007 and a Director of Northeast Utilities Foundation since January 1, 2005; previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Leon J. Olivier

Executive Vice President - Operations of NU since February 13, 2007; Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001; Previously Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; President and Chief Operating Officer of CL&P from September 2001 to January 2005.

Shirley M. Payne

Vice President - Accounting and Controller of NU since February 13, 2007, and of CL&P, PSNH and WMECO since January 29, 2007. Previously Vice President, Corporate Accounting and Tax of TECO Energy, Inc. from July 2000 to January 26, 2007 and Tax Officer of TECO Energy, Inc. from April 1999 to January 26, 2007.

James B. Robb

Senior Vice President, Enterprise Planning and Development of NUSCO since September 4, 2007, and performs policy-making functions for NU. Previously Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.

Charles W. Shivery

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO since January 19, 2007 and a Director of Northeast Utilities Foundation since March 3, 2004. Previously, President (interim) of NU from January 1, 2004 to March 29, 2004; President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.

None of the above Executive Officers serves as an Executive Officer pursuant to any agreement or understanding with any other person.

Item 4.

Submission Of Matters To a Vote of Security Holders

No event that would be described in response to this item occurred with respect to us or CL&P.

The information called for by Item 4 is omitted for PSNH and WMECO pursuant to Instruction I (2)(c) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries.)

Part II

Item 5.

Market for The Registrants' Common Equity and Related Stockholder Matters

NU. Our common shares are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low closing sales prices for the past two years, by quarters, are shown below.


Year	Quarter	High		Low

2007	First	$	32.77	$	27.40
	Second		33.53		27.37
	Third		29.42		26.93
	Fourth		32.83		27.98

2006	First	$	20.21	$	19.25
	Second		20.97		19.24
	Third		23.57		20.84
	Fourth		28.81		23.38

There were no purchases made by or on behalf of our company or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2007. Information with respect to the performance of our common shares is contained in the "Share Performance Chart" from our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

As of January 31, 2008, there were 47,891 common shareholders of our company on record. As of the same date, there were a total of 175,969,591 common shares issued, including 1,110,400 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.

On February 12, 2008, our Board of Trustees declared a dividend of 20 cents per share, payable on March 31, 2008, to shareholders of record as of March 1, 2008.

On November 13, 2007, our Board of Trustees declared a dividend of 20 cents per share, payable on December 31, 2007, to shareholders of record as of December 1, 2007.

On May 7, 2007, our Board of Trustees declared a dividend of 20 cents per share, payable on September 28, 2007, to shareholders of record as of September 1, 2007.

On April 10, 2007, our Board of Trustees declared a dividend of 18.75 cents per share, payable on June 29, 2007, to shareholders of record on June 1, 2007.

On February 13, 2007, our Board of Trustees declared a dividend of 18.75 cents per share, payable on March 31, 2007, to shareholders of record as of March 1, 2007.

On November 13, 2006, our Board of Trustees declared a dividend of 18.75 cents per share, payable on December 30, 2006, to shareholders of record as of December 1, 2006.

On May 9, 2006, our Board of Trustees declared a dividend of 18.75 cents per share, payable on September 29, 2006, to shareholders of record as of September 1, 2006.

On April 11, 2006, our Board of Trustees declared a dividend of 17.5 cents per share, payable on June 30, 2006, to shareholders of record on June 1, 2006.

On February 14, 2006, our Board of Trustees declared a dividend of 17.5 cents per share, payable on March 31, 2006, to shareholders of record as of March 1, 2006.

Information with respect to dividend restrictions for us, CL&P, PSNH, and WMECO is contained in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the caption "Liquidity" and in the "Notes to Consolidated Financial

Statements," within our company’s and each company's respective 2007 Annual Reports to Shareholders, which information is incorporated herein by reference.

CL&P, PSNH and WMECO. There is no established public trading market for the common stock of CL&P, PSNH and WMECO. The common stock of CL&P, PSNH and WMECO is held solely by NU.

During 2007 and 2006, CL&P approved and paid $79.2 million and $63.7 million, respectively, of common stock dividends to NU.

During 2007 and 2006, PSNH approved and paid $30.7 million and $41.7 million, respectively, of common stock dividends to NU.

During 2007 and 2006, WMECO approved and paid $12.8 million and $7.9 million, respectively, of common stock dividends to NU.

For information regarding securities authorized for issuance under equity compensation plans, see Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters," included in this Annual Report on Form 10-K.

Item 6.

Selected Financial Data

NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within CL&P's 2007 Annual Report, which information is incorporated herein by reference.

PSNH. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within PSNH's 2007 Annual Report, which information is incorporated herein by reference.

WMECO. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within WMECO's 2007 Annual Report, which information is incorporated herein by reference.

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

NU. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within CL&P's 2007 Annual Report, which information is incorporated herein by reference.

PSNH. With respect to PSNH's results of operations, reference is made to information under the heading "Results of Operations" contained within PSNH's 2007 Annual Report, which information is incorporated herein by reference.

WMECO. With respect to WMECO's results of operations, reference is made to information under the heading "Results of Operations" contained within WMECO's 2007 Annual Report, which information is incorporated herein by reference.

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

Select Energy utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components). Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices. As the NU Enterprises' businesses are exited, the risks associated with commodity prices are expected to be reduced.

NU Enterprises - Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's wholesale portfolio, which includes a non-derivative power purchase contract, which would result from a hypothetical change in the future market

price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.

A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10% change in forward market prices. At December 31, 2007, Select Energy has calculated the market price resulting from a 10% change in forward market prices of those contracts. A 10% increase in prices for all products would have resulted in a pre-tax increase in fair value of $0.9 million and a 10% decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $1.3 million. A 10% increase in energy prices would have resulted in a $6.8 million pre-tax decrease, and a 10% decrease in energy prices would have resulted in a $6.4 million pre-tax increase. A 10% increase/(decrease) in capacity prices would have resulted in a $2.2 million pre-tax increase/(decrease). A 10% increase/(decrease) in ancillary prices would have resulted in a $5.5 million pre-tax increase/(decrease).

The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at December 31, 2007 are not necessarily representative of the results that will be realized. These transactions are accounted for at fair value, and changes in market prices impact earnings.

Other Risk Management Activities

Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. At December 31, 2007, approximately 90% (83% if we include the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rates, including the rate on long-term debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.7 million. At December 31, 2007, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate long-term debt.

Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council. The Risk Oversight Council is comprised of individuals from outside of the management of these activities that create these risk exposures and functions to ensure compliance with our stated risk management policies.

We track and re-balance the risk in our portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.

The New York Mercantile Exchange (NYMEX) traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.

At December 31, 2006, Select Energy maintained collateral balances from counterparties of $0.1 million. These amounts are included in current liabilities - other on the accompanying consolidated balance sheet. There were no such balances at December 31, 2007. Select Energy also has collateral balances deposited with counterparties of $18.9 million and $48.5 million at December 31, 2007 and 2006, respectively.

Our regulated companies have a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises. However, our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with

energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk.

We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the company. ERM involves the application of a well-defined, enterprise-wide methodology that will enable our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERM process will identify every risk or event that could impact our financial condition or results of operations. The findings of this process are periodically discussed with our Board of Trustees.

Additional quantitative and qualitative disclosures about market risk are set forth in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained within our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

Item 8.

Financial Statements and Supplementary Data

NU. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income/(Loss)," "Consolidated Statements of Comprehensive Income/(Loss)," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained within our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within CL&P's 2007 Annual Report, which information is incorporated herein by reference.

PSNH. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within PSNH's 2007 Annual Report, which information is incorporated herein by reference.

WMECO. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within WMECO's 2007 Annual Report, which information is incorporated herein by reference.

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

No events that would be described in response to this item have occurred with respect to us, CL&P, PSNH or WMECO.

Item 9A.

Controls and Procedures

We are responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements and other sections of this Annual Report on Form 10-K. NU’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

We are responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, we concluded that our internal controls over financial reporting were effective as of December 31, 2007.

We, as well as CL&P, PSNH and WMECO, undertook separate evaluations of the design and operation of our disclosure controls and procedures to determine whether we are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and forms of the SEC. This evaluation was made under our supervision and with our participation, including our principal executive officers and principal financial officer, as of the end of the period covered by this Annual Report on Form 10-K. Our principal executive officers and principal financial officer have concluded, based on their review, that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in our reports that we file under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to our management, including our principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no changes in internal controls over financial reporting for us, CL&P, PSNH and WMECO during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

Item 9B.

Other Information

No information is required to be disclosed under this item at December 31, 2007, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2007.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

The information in Item 10 is provided as of February 26, 2008 except where otherwise indicated.

Certain information required by this Item 10 is omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.

NU and CL&P

In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections captioned "Election of Trustees," "Governance of Northeast Utilities" and the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, expected to be dated March 31, 2008, which will be filed with the SEC pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

The names and ages of the executive officers of NU and the executive officers and Directors of CL&P, and the positions they hold, held, or have been elected to (as of February 26, 2008), and their business experience during the past five years, are set forth below.

Name

Age

Office and Business Experience During Past Five Years

Gregory B. Butler

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006. Director of Northeast Utilities Foundation, Inc. since December 1, 2002. Previously, Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005, and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.

Peter J. Clarke

Vice President of Shared Services of NUSCO, a subsidiary of NU, since January 1, 2008, and performs policy-making functions for NU and CL&P. Previously, Vice President - Customer Operations of CL&P and Yankee Gas from July 1, 2006 to December 31, 2007; Vice President - Customer Operations and Relations of CL&P from January 17, 2005 to June 30, 2006; and Director - System Projects of CL&P from March 11, 2002 to January 16, 2005.

Cheryl W. Grisé

Executive Vice President of NU from December 1, 2005 to July 1, 2007; Chief Executive Officer of CL&P from September 10, 2002 to January 15, 2007. Previously Chief Executive Officer of PSNH and WMECO from September 10, 2002 to January 15, 2007, a Director of CL&P from May 1, 2001 to January 15, 2007, of PSNH from May 14, 2001 to January 15, 2007 and of WMECO from June 2001 to January 15, 2007; previously President - Utility Group of NU from May 2001 to December 1, 2005.

Jean M. LaVecchia

Vice President - Human Resources of NUSCO, a subsidiary of NU, since June 30, 2005, and performs policy-making functions for NU and CL&P; also a Director of Northeast Utilities Foundation since January 30, 2007. Previously Vice President - Human Resources and Environmental Services from May 1, 2001 to June 30, 2005.

David R. McHale

Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO since January 1, 2005. Director of PSNH and WMECO since January 1, 2005 and CL&P since January 15, 2007. Director of Northeast Utilities Foundation since January 1, 2005. Previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Raymond P. Necci*

President and Chief Operating Officer and a Director of CL&P and Yankee Gas since January 17, 2005. Director of Northeast Utilities Foundation since April 1, 2006. Previously, Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005.

Leon J. Olivier

Executive Vice President-Operations of NU since February 13, 2007, and Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007. Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001; also a Director of Northeast Utilities Foundation since April 1, 2006. Previously, Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005, and President and Chief Operating Officer of CL&P from September 2001 to January 2005.

Shirley M. Payne

Vice President - Accounting and Controller of NU since February 13, 2007, and of CL&P, PSNH and WMECO since January 29, 2007. Previously, Vice President, Corporate Accounting and Tax of TECO Energy, Inc. from July 2000 to January 26, 2007 and Tax Officer of TECO Energy, Inc. from April 1999 to January 26, 2007.

James B. Robb

Senior Vice President, Enterprise Planning and Development, NUSCO since September 4, 2007, and performs policy-making functions for NU and CL&P. Previously, Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.

Charles W. Shivery

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004 and Chairman and a Director of CL&P, PSNH and WMECO since January 19, 2007. Also a Director of Northeast Utilities Foundation since March 3, 2004. Previously, President (interim) of NU from January 1, 2004 to March 29, 2004; President – Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.

* Executive Officer of CL&P only.

There are no family relationships between any director or executive officer and any other director or executive officer of NU and CL&P and none of the above Executive Officers or Directors serves as an Executive Officer or Director pursuant to any agreement or understanding with any other person. Our Executive Officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.

CL&P obtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees. CL&P does not have its own audit committee or, accordingly, an audit committee financial expert.

CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT

Each of NU, CL&P, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and a Standards of Business Conduct which is applicable to all Directors, officers, employees, contractors and agents of NU, CL&P, PSNH and WMECO. The Code of Ethics and the Standards of Business Conduct have both been posted on the NU web site and are available at www.nu.com/investors/corporate_gov/default.asp on the Internet. Any amendments to or waivers from the Code of Ethics and Standards of Business Conduct will be posted on the website. Any such amendment or waiver would require the prior consent of the Board of Directors or an applicable committee thereof.

Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:

Ms. O. Kay Comendul

Assistant Secretary

Northeast Utilities Service Company

P.O. Box 270

Hartford, CT 06141

Item 11. Executive Compensation

Incorporated herein by reference is certain information contained in the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, which is expected to be filed with the SEC on or about March 31, 2008. This information appears under the sections captioned "Compensation Discussion and Analysis" plus the related subsections, and "Compensation Committee Report" plus the related subsections.

CL&P

CL&P is a wholly-owned subsidiary of Northeast Utilities with a board of directors consisting entirely of executive officers of NU system companies. As such, CL&P does not have a compensation committee. NU’s Compensation Committee of the Board of Trustees is responsible for compensation and benefits programs for the executive officers of CL&P. The compensation described for each executive officer in this Item 11 was for all services in all capacities to NU and its subsidiaries. All salaries, annual incentive amounts and long-term incentive amounts paid to these executive officers were paid by Northeast Utilities Service Company, a service company subsidiary of NU.

For purposes of this Item 11, references to "we," "our," and "us" refer to CL&P.

COMPENSATION DISCUSSION AND ANALYSIS

OVERALL OBJECTIVES OF EXECUTIVE COMPENSATION PROGRAM

The fundamental objective of the Executive Compensation Program for NU System companies is to motivate executives and key employees to support NU’s strategy of investing in and operating businesses that benefit customers, employees, and shareholders. As a holding company for several regulated utilities, NU is also responsible to its franchise customers to provide energy services reliably, safely, with respect for the environment and its employees, and at a reasonable cost.

The Executive Compensation Program supports its fundamental objective through the following design principles:

Attract and retain key executives by providing total compensation competitive with that of other executives employed by companies of similar size and complexity. The program relies on compensation data obtained from consultants’ surveys of companies and from a customized peer group to ensure that compensation opportunities are competitive and capable of attracting and retaining executives with the experience and talent required to achieve our strategic objectives. As NU continues to grow and improve its transmission, distribution, and regulated generation systems, having the right talent will be critical.

Establish performance-based compensation that balances rewards for short-term and long-term business results. The program motivates executives to run the business well in the short term, while executing the long-term business plan to benefit both NU’s customers and shareholders. The program aims to strike a balance between the short- and long-term programs so that they work in tandem. It also ensures that long-term objectives are not sacrificed to achieve short-term goals or vice versa.

Incentive plan performance criteria are based on a combination of financial, operational, stewardship, and strategic goals that are essential to the achievement of NU’s business strategies. This linkage to critical goals helps to align executives with NU’s key stakeholders—customers, employees, and shareholders. The long-term program also compares performance relative to a group of comparable utility companies.

Reward corporate and individual performance. Overall compensation has many metrics based on corporate performance but is also highly differentiated based on individual performance. The annual incentive program rewards both team performance (measured by adjusted net income) and individual performance (including individualized financial, operational, stewardship and strategic metrics). Long-term incentives are composed of a performance cash program and restricted share units (RSUs). The performance cash program pays out based on the achievement of NU corporate goals (cumulative net income, average ROE, average credit rating and relative total shareholder return). The size of RSU grants reflects NU corporate performance during the preceding fiscal year as well as individual performance and contribution, but the ultimate value of the RSUs is based on NU’s corporate total shareholder return.

Encourage long-term commitment to the company. Utility companies provide a public service and have a long-term commitment to ensure that customers receive reliable service day after day. Meeting this commitment requires specialized skills and institutional knowledge that are learned over time through local industry experience. These skills include familiarity with the regions and communities that we serve, government regulations, and long-term energy policies. In addition, utility companies rely on long-term capital investments to serve their customers.

As a result, public utilities benefit from long-service employees. NU has structured its executive compensation programs for the NU System Companies to build long-term commitment as well as shareholder alignment. Providing competitive compensation opportunities and offering programs such as RSUs and supplemental retirement benefits that vest and increase in value over time encourage long-term employment. Executive share ownership guidelines are another program component intended to build long-term shareholder alignment and commitment.

The executive officers listed in the Summary Compensation Table in this Annual Report on Form 10-K whose compensation is discussed in this CD&A are referred to as the "Named Executive Officers" or "NEOs." For 2007, CL&P’s Named Executive Officers are:

Charles W. Shivery, Chairman of the Board, President and Chief Executive Officer of NU; Chairman and a Director of CL&P

David R. McHale, Senior Vice President and Chief Financial Officer of NU and CL&P; Director of CL&P

Leon J. Olivier, Executive Vice President-Operations of NU; Chief Executive Officer and Director of CL&P

Raymond P. Necci, President and Chief Operating Officer of CL&P and Yankee Gas

Gregory B. Butler, Senior Vice President and General Counsel of NU and CL&P

Cheryl W. Grisé, Chief Executive Officer of CL&P through January 15, 2007; Executive Vice President of NU through July 1, 2007

ELEMENTS OF 2007 COMPENSATION

Set forth below is a brief description and the objective of each material element and the additional benefits of NU’s executive compensation program:


Compensation Element	Description	Objective

Base Salary	Fixed compensation Usually increased annually during the first quarter based on individual performance, competitive market levels, strategic importance of the role and experience in the position	Compensate officers for fulfilling their basic job responsibilities Provide base pay commensurate with the median salaries paid to executive officers holding comparable positions in other utility companies and companies in general industry Aid in attracting and retaining qualified personnel

Annual Incentive Program	Variable compensation based on performance against pre-established annual team and individual goals that is paid in cash in the first quarter following the end of the program year	Promote the achievement of annual performance objectives that represent business success for the company, the executive, and his or her business unit or function

Long-Term Incentive Program	Variable compensation consisting of one-half RSUs and one-half performance cash (see below)

· Restricted share units (RSUs)	NU common share units, which vest over a three-year period, granted based on corporate performance and individual performance and contribution	Align executive and shareholder interests through share performance and share ownership Encourage a long-term commitment to the company

· Performance Cash Program	Long-term cash incentive that rewards individuals for NU corporate performance over a three-year period based on achieving pre-established levels of: · Cumulative net income · Average ROE · Average credit rating · Total shareholder return relative to a group of comparable utility companies	Reward performance on key corporate priorities that are also key drivers of total shareholder return performance Encourage long-term thinking and commitment to the company

Supplemental Benefits	Supplemental Executive Retirement Plan (SERP), Nonqualified Deferred Compensation, and Perquisites	Supplemental benefits intended to help NU attract and retain executive officers critical to its success by reflecting competitive practices


· Supplemental Executive Retirement Plan (Supplemental Plan)	Non-qualified pension plan, providing additional retirement income to officers beyond payments provided in NU’s standard defined benefit retirement plan, consisting of: · A defined benefit "make-whole" plan. · A supplemental "target" benefit (certain senior vice presidents and above only) · Exempt employees, including executives, hired after 2005 are ineligible for these benefits	Compensate for Internal Revenue Code limits on qualified plans Aid in retention of executives and enhance long-term commitment to the company

· Other Nonqualified Deferred Compensation (Deferral Plan)	Opportunity to defer base salary and annual incentives, using the same investment vehicles as the NU qualified 401(k) plan, and receive matching contributions otherwise capped by Internal Revenue Code limits on qualified plans Each year’s match vests after three years or at retirement For executives hired after 2005 who are ineligible to participate in NU’s defined benefit pension plan, NU makes contributions of 2.5%, 4.5% and 6.5%, as applicable based on the relevant bracket for the sum of the officer’s age and years of service, on cash compensation that would otherwise be capped by Internal Revenue Code limits on qualified plans	Aid executives in tax planning by allowing them to defer taxes on certain compensation Compensate for Internal Revenue Code limits on qualified plans Provide a competitive benefit Aid in retention and enhance long-term commitment to the Company

· Perquisites	Financial planning and tax preparation reimbursement benefit Executive physical examination reimbursement plan Other perquisites including reimbursement of spousal travel expenses for business purposes	Encourage use of a professional to prepare tax returns and maximize value of compensation Encourage executives to undergo regular health checks to reduce the risk of losing critical employees Discretionary benefits intended to help executive officers be more productive and efficient

Employment Agreements	Employment agreements with certain of our Named Executive Officers provide benefits and payments upon involuntary termination and termination following a change of control. Mr. Olivier and Mr. Necci participate in a "Special Severance Program" that provides other benefits and payments upon termination of employment resulting from a change-in-control	Meet competitive expectation of employment Help focus executive on shareholder interests Provide income protection in the event of involuntary loss of employment

MIX OF COMPENSATION ELEMENTS

NU strives to provide executive officers of its system companies with base salary, annual incentive compensation and long-term incentive compensation opportunities based on performance at or above the market median over time. NU establishes the market median as described under the caption entitled Market Analysis, below. As a result, the annual and long-term incentive target percentages for the Named Executive Officers are approximately equal to competitive median incentives.

With respect to incentive compensation, the Compensation Committee believes it is important to balance short-term goals, such as generating earnings per share, with longer term goals, such as long-term value creation and maintaining a strong balance sheet. As the executive officers are promoted to more senior positions, they assume increased responsibility for implementing the company’s long-term business plans and strategies, and a greater proportion of their total compensation is based on performance with a long-term focus. Historically, long-term incentive compensation has been weighted more significantly than short-term incentives at target, reflecting the longer-term nature of our business plans. Accordingly, as depicted in the table below, the long-term incentive compensation targets of each of the NEOs, as percentages of base salary, are slightly higher than the median targets reflected in the utility and general industry survey data that we use to analyze executive compensation. As a result, short-term incentive compensation is generally lower. The survey data for long-term incentive compensation is based on the present value of actual long-term incentive grants. We discuss this survey data in greater detail below under the caption entitled Market Analysis.

The Compensation Committee determines total compensation for each executive officer based on the relative authority, duties and responsibilities of each office within the NU system. Mr. Shivery’s responsibilities, as Chairman, President and Chief Executive Officer of NU, for the daily operations and management of the NU System companies are significantly greater than the duties and responsibilities of our other executive officers. As a result, our Mr. Shivery’s compensation is significantly higher than the compensation of our other executive officers. The Compensation Committee regularly reviews market compensation data for executive officer positions similar to those held by our executive officers, including Mr. Shivery, and this market data continues to indicate that chief executive officers are typically paid significantly more than other executive officers. For 2007, target annual incentive and long-term incentive compensation opportunities for Mr. Shivery were 100% and 300% of base salary, respectively. For the remaining NEOs, target annual incentive compensation opportunities ranged from 50% to 65% of base salary and target long-term incentive compensation opportunities ranged from 85% to 150% of base salary. Mr. Olivier’s long-term incentive compensation target was fixed at 125% of his base salary, which is below a target of 150% of base salary typically provided to executive officers at his level, because his total compensation includes a special retirement benefit. Mrs. Grisé, who resigned as chief executive officer of CL&P effective January 15, 2007 and retired from NU effective July 1, 2007, did not participate in the 2007 – 2009 Long-Term Incentive Program.

The following table sets forth the contribution to 2007 Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for each Named Executive Officer. Annual incentive awards and performance cash awards under the long-term incentive program were performance based and, accordingly, were at risk.


	Percentage of (TDC) at Target
		Performance Based (1)
			Long-Term Incentives (2)
Named Executive Officer	Base Salary	Annual Incentive	Performance Cash	RSUs (3)	TDC
Charles W. Shivery	20%	20%	30%	30%	100%
David R. McHale	32%	20%	24%	24%	100%
Leon J. Olivier	34%	22%	22%	22%	100%
Raymond P. Necci	43%	21%	18%	18%	100%
Gregory B. Butler	32%	20%	24%	24%	100%
Cheryl W. Grisé (4)	61%	39%	--%	--%	100%

(1)

The annual incentive compensation element and the long-term incentive compensation element are performance-based.

(2)

Long-term incentive compensation at target consists of equal proportions of performance cash awards and RSUs.

(3)

RSUs are granted based on annual NU corporate and individual performance, but vest over three years contingent upon continued employment. The percentages reflect the target value of the RSUs on the date of grant.

(4)

Mrs. Grisé resigned as chief executive officer of CL&P effective January 15, 2007 and retired from NU effective July 1, 2007.

MARKET ANALYSIS

The Compensation Committee strives to provide our executive officers with compensation opportunities over time at or above the median compensation levels for executive officers of companies comparable to us. The Committee determined executive officer TDC levels in two steps. First, the Committee determined the "market" values of executive officer compensation elements (e.g., base salaries, annual incentives and long-term incentives) as well as total compensation using compensation data obtained from other companies. Th1e Committee reviewed compensation data obtained from two sources: (i) utility and general industry survey data and (ii) customized peer group data. The Committee then reviewed the compensation elements for each executive officer with respect to the median of these market values, and considered individual performance, experience and internal pay equity to determine the amount, if any, by which the various compensation elements should exceed the median market values. Significantly, the Committee has not made a commitment to compensate our executive officers through a firm and direct connection between the compensation paid by us and the compensation paid by any of the companies from which the utility and general industry survey data and the customized peer group data was obtained.

Set forth below is a description of the sources of the compensation data used by the Compensation Committee:

Utility and general industry survey data. The Committee analyzed compensation information obtained from surveys of diverse groups of utility and general industry companies that represent our market for executive officer talent. The Committee used the utility and general industry survey data to determine base salaries and incentive opportunities. The compensation consultant reviewed subsets of survey data applicable to utility companies correlated to reflect entities similar in size to us. Then the Committee compared utility-specific executive officer positions, including Mr. Olivier, who serves as NU’s Executive Vice President – Operations as well as CL&P’s Chief Executive Officer, to utility-specific market values. For executive officer positions that have counterparts in general industry, including NU’s Chief Executive Officer; Senior Vice President and Chief Financial Officer; and Senior Vice President and General Counsel, the Committee averaged general industry comparisons with utility industry comparisons weighted equally.

Customized peer group data. The Committee also evaluated compensation data obtained from reviews of proxy statements from a customized group of peer utility companies consisting of: (i) utilities that are substantially regulated with annual revenues that ranged from $2.5 billion to $12 billion with median annual revenues of $5.6 billion; and (ii) utilities that are less regulated and closer in size to NU, with annual revenues that ranged from $3 billion to $7 billion. Although we do not consider utilities that are less regulated to be direct performance peers, these companies represent potential sources of talent. The Committee considered data only for those executive officer positions where there is a title match. For 2007, this group consisted of the following 22 companies:


Allegheny Energy, Inc.	Great Plains Energy Incorporated	PPL Corporation
Alliant Energy Corporation	NiSource Inc.	Progress Energy, Inc.
Ameren Corporation	NSTAR	Puget Energy, Inc.
CenterPoint Energy, Inc.	OGE Energy Corp.	SCANA Corporation
CMS Energy Corporation	PG&E Corporation	Sierra Pacific Resources
Consolidated Edison, Inc.	Pepco Holdings, Inc.	TECO Energy, Inc.
Energy East Corporation	Pinnacle West Capital Corporation	Wisconsin Energy Corporation
		Xcel Energy Inc.

The Committee used compensation data obtained from these companies for insights into incentive compensation design practices and compensation levels, although no specific actions were taken in 2007 directly as a result of this data. In 2007, the Committee also used a subset of this group for performance comparisons under the performance cash program as described below under the caption entitled 2007 – 2009 Long-Term Incentive Program. The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data to ensure that they continue to represent market median levels. Adjustments are made gradually over time to avoid radical changes.

The Compensation Committee also sets supplemental benefits at levels that provide market-based compensation opportunities to the executive officers. Compensation includes perquisites to the extent they serve business purposes. The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, sometimes including data obtained from companies in the customized peer group. Benefits are adjusted occasionally to maintain market parity. When the market trend for supplemental benefits reflects a general reduction, (e.g., the elimination of defined benefit pension plans), the Committee has reduced these benefits only for newly hired officers. The Committee reviewed NU’s supplemental retirement practices most recently in 2005 and 2006, as described in more detail below under the caption entitled Supplemental Benefits.

BASE SALARY

The Compensation Committee reviews executive officers’ base salaries annually. The Committee considers the following specific factors when setting or adjusting base salaries:

Annual individual performance appraisals

Market pay movement across industries (determined through market analysis)

Targeted market pay positioning for each executive officer

Individual experience and years of service

Changes in corporate focus with respect to strategic importance of a position

Internal equity

Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals. From time-to-time, weak corporate performance has caused salary increases to be postponed, but the Committee prefers to reflect subpar corporate performance through the variable pay components.

Based on these considerations, the Compensation Committee acting jointly with the Corporate Governance Committee recommended to NU’s Board of Trustees a salary increase for Mr. Shivery of 6.4%, which was approved by the Board of Trustees. Mr. Shivery’s base salary was increased to the competitive median to recognize his level of contribution in his role as Chief Executive Officer of NU. The Compensation Committee also approved base salary increases in 2007 as follows: Mr. McHale: 20.0%; Mr. Olivier: 14.7%; Mr. Necci: 5.0%; and Mr. Butler: 7.0%. The Compensation Committee approved more significant base salary increases for Messrs. Olivier and McHale so that the base salary of each of them approached the median base salary for their respective positions. Mr. Olivier’s salary increase was primarily related to his promotion to Executive Vice President - Operations of NU in early 2007. Mr. McHale’s salary increase was primarily based on his increased experience and individual performance during 2006. Mr. Necci’s increase brought his base salary closer to median, and Mr. Butler’s increase recognized increasing competitive pay levels for top legal professionals and his responsibilities in addition to oversight of the legal function. Mrs. Grisé did not receive a base salary increase for 2007 because she had previously announced her plans to retire in 2007.

INCENTIVE COMPENSATION

The annual incentive program and the long-term incentive program are provided under the Northeast Utilities Incentive Plan, which was approved by NU’s shareholders at NU’s 2007 Annual Meeting of Shareholders. The annual incentive program provides cash compensation intended to reward performance under our annual operating plans. The long-term incentive program is designed to reward demonstrated performance and leadership, motivate future superior performance, align the interests of the executive officers with those of our shareholders and retain the executive officers during the term of awards. Awards under the long-term incentive program consist of two elements of compensation, RSUs and performance cash. The Compensation Committee selected RSUs as the equity component of long-term awards because utility companies create value for shareholders through the payment of periodic dividends as well as through share price appreciation. The annual and long-term programs are intended to work in tandem so that achievement of our annual goals leads us towards attainment of our long-term financial goals.

Incentive awards are based on objective financial performance goals established by the Compensation Committee with the advice of the Finance Committee. The Compensation Committee sets the performance goals annually for new annual incentive and long-term incentive program performance periods, depending on NU’s business focus for the then-current year and the long-term strategic plan. The Compensation Committee has modified the performance goals more significantly in recent years in connection with NU’s increased focus on its regulated utility businesses.

2007 ANNUAL INCENTIVE PROGRAM

The 2007 Annual Incentive Program consisted of a team goal plus individual goals for each NEO. The Compensation Committee set the annual incentive compensation targets for 2007 at 100% of base salary for Mr. Shivery and at 50% to 65% of base salary for the other NEOs. The annual incentive compensation targets are used as guidelines for the determination of annual incentive payments, but actual annual incentive payments may vary significantly from these targets, depending on individual and corporate performance. Actual annual incentive payments may equal up to two times target if NU achieves superior financial and operational results. The opportunity to earn up to two times the incentive target reflects the Compensation Committee’s belief that executive officers have significant ability to affect performance outcomes. However, NU does not pay annual incentive awards if minimum levels of financial performance are not met.

If NU’s earnings were to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct, the Sarbanes-Oxley Act of 2002 would require Mr. Shivery and our Chief Financial Officer to reimburse NU for certain incentive compensation received by each of them. To the extent that reimbursement were not required under Sarbanes-Oxley, NU’s Incentive Plan would require any employee whose misconduct or fraud caused such restatement, as determined by NU’s Board of Trustees, to reimburse NU for any incentive compensation received by him or her. To date, there have been no restatements to which either the Sarbanes-Oxley reimbursement provisions or the Incentive Plan reimbursement provisions would apply.

2007 Team Goal

The objective of the 2007 Annual Incentive Program team goal for the NEOs was to achieve an adjusted net income for NU (ANI) target established by the Compensation Committee. ANI is defined as consolidated NU net income adjusted to exclude the effect of certain nonrecurring income and expense items or events. The Committee uses ANI because it believes that ANI serves as an indicator of ongoing operating performance. The minimum payout under the team goal was set at 50% of target and would occur if actual ANI was at least 90% of the ANI target. The maximum payout under the team goal was set at 200% of target and would occur if actual ANI was at least 10% above the ANI target. We would pay annual incentive compensation related to individual goals only if actual ANI was at least 80% of the ANI target.

For 2007, the Compensation Committee established the ANI target at $219.4 million. The ANI target reflects the midpoint of the range of internal ANI estimates calculated at the beginning of the year. The ANI thresholds for the individual and team goals appear below (dollars in millions):


Threshold For Individual Goals (20% below ANI Goal)	Minimum Team Goal (10% below ANI Goal)	2007 ANI Goal	Maximum Team Goal (10% above ANI Goal)	Actual 2007 ANI
$175.5	$197.5	$219.4	$241.3	$257.9

The Compensation Committee set the ANI threshold for achieving individual goals and the minimum and maximum team goals in its discretion based on the following factors:

An assessment of the potential volatility in results;

The degree of difficulty in achieving the ANI target; and

The minimum acceptable ANI.

At the time that the Compensation Committee established the performance goals for 2007, the Committee also considered and agreed upon exclusions from ANI consisting of certain nonrecurring income and expense items or events that were either beyond the control of management generally or related to a decision by the Committee not to penalize executive officers for making correct strategic business decisions. The number of exclusions reflects the complexity of NU’s business as it continues to increase its focus on its regulated utility businesses. The Compensation Committee approved all final exclusions from ANI. In 2007, the income and expense items set forth below were excluded from ANI in 2007. The Net Adjustments to ANI did not impact the achievement of the maximum team goal.


Excludable Categories	Specific 2007 Adjustments ($ in millions)
Changes to net income as the result of accounting or tax law changes	$	(12.8)
Unexpected costs relating to nuclear decommissioning		1.4
Unexpected costs related to environmental remediation at Holyoke
Water Power Company		--
Unbudgeted charitable contributions		(1.8)
Impairments on goodwill acquired before 2002 (more than five years
prior to the beginning of this program period)		--
Changes to net income resulting from any settlement of, or final
decision in, ongoing litigation with Consolidated Edison		--
Mark-to-market impacts of agreements to which NU or any of NU
competitive subsidiaries are parties		(3.8)
Unusual IRS/regulatory decisions		--
Divestiture or discontinuance of a significant segment or component
of NU's competitive businesses		(2.4)
Net benefit to income from customer service integration project delay *		6.4
Net Adjustments:	$	(13.0)

Excluded from ANI at the discretion of the Compensation Committee.

2007 Individual Goals

The 2007 Annual Incentive Program individual goals included various financial, operational, stewardship, and strategic metrics that are drivers of overall corporate performance. The achievement of individual goals would result in an annual incentive payment only if actual ANI is at least 80% of the ANI target. This ANI threshold satisfies the requirements of Section 162(m) of the Internal Revenue Code. Upon achieving this ANI threshold, the maximum payout is possible for individual goals for every participant.

The Committee acts in its discretion under Section 162(m) and related Internal Revenue Service (IRS) rules and regulations to ensure that incentive compensation payments are "qualified performance based compensation" not subject to the $1 million limitation on deductibility. The Compensation Committee, acting jointly with the Corporate Governance Committee, determines Mr. Shivery’s proposed annual incentive program payment based on the extent to which individual and NU corporate goals have been achieved. The Compensation Committee recommends to the Board of Trustees for approval the proposed award for Mr. Shivery. For the remaining

NEOs, Mr. Shivery recommends annual incentive awards to the Compensation Committee for its approval. NEOs are eligible to receive up to two times the annual incentive compensation target for the individual portion of the award.

Goal Weightings for 2007

The following table sets forth the weighting of the annual incentive program team goal and individual goals of each NEO’s compensation for 2007. These weightings reflect the Compensation Committee’s desire to balance individual accountability with teamwork across the organization. Individual goals collectively range from 40% to 70% of the total annual incentive program target. Certain of our NEO’s individual performance goals are subjective in nature and cannot be measured either by reference to existing financial metrics or by using pre-determined mathematical formulas. The Committee believes that it is important to exercise judgment and discretion when determining the extent to which each NEO satisfies subjective individual performance goals. The Committee considers these goals along with several factors, including overall individual performance, corporate performance, prior year compensation and the other factors discussed below.


Leon J. Olivier Executive Vice President - Operations of NU; Chief Executive Officer of CL&P	40%	60%	Manage the capital program budget (45% of individual goals). Achieve significant progress in New England East-West Solution, a joint project with National Grid designed to improve reliability and electric transfer capability in Springfield, Massachusetts and central and northeast Connecticut (15% of individual goals). Achieve successful outcomes in federal and state energy regulatory policy and ratemaking proceedings (20% of individual goals). Fully integrate new computer system for managing work requests, design, scheduling, construction and closeout processes (10% of individual goals). Comply with federal and state energy regulatory requirements (10% of individual goals).

Raymond P. Necci President and Chief Operating Officer of CL&P and Yankee Gas	30%	70%	Achieve Net Income goals for CL&P and Yankee Gas (20% of individual goals). Achieve a resolution of CL&P and Yankee Gas delivery rate cases that reasonably support operational and financial objectives (20% of individual goal). Complete all key project category milestones associated with the LNG project on schedule and within budget (10% of individual goal). Improve reliability performance of CL&P and Yankee Gas (20% of individual goals). Achieve CL&P and Yankee Gas safety performance (20% of individual goal). Implement a comprehensive self assessment program to identify and correct procedure compliance weaknesses (10% of individual goal).

Gregory B. Butler Senior Vice President and General Counsel	50%	50%	Achieve successful outcomes in federal and state energy regulatory policy and ratemaking proceedings (40% of individual goals). Manage his areas of responsibility (45% of individual goals). Position NU to assume a leadership role in state and federal regulatory matters; develop and implement New England energy policy (15% of individual goals).

Cheryl W. Grisé Former Chief Executive Officer	40%	60%	Effectively transition from active role in management to advisory role in anticipation of retirement (100% of individual goals).

2007 Results

The 2007 actual ANI was $257.9 million, which exceeded the maximum ANI amount for annual program team goal. As a result, a portion of the total annual incentive payment to each NEO was attributable to achieving the maximum team goal. In addition, the 2007 actual ANI also exceeded the individual goal threshold. Accordingly, the balance of the annual incentive payment to each NEO was based on the extent to which each NEO achieved his or her individual goals.

Annual Incentive Payment for Mr. Shivery

The Compensation Committee and the Corporate Governance Committee assessed Mr. Shivery’s performance on his individual goals described in the table above. Set forth below is a description of the Committees’ assessment of Mr. Shivery’s performance against these goals:

Mr. Shivery’s execution of NU’s long-term strategic plan as well as its operating and capital plans was above expectations. In the aggregate, major transmission projects were on or ahead of schedule and at or below budget. Implementation of the $6 billion capital investment program is on track and has yielded increased earnings and improved reliability. In 2007, NU’s transmission business very successfully completed a compliance audit by the North Atlantic Electric Reliability Corporation.

Overall customer satisfaction ratings improved for all but one business unit.

On balance, Mr. Shivery met expectations relative to rate-making and regulatory policy proceedings. Rate cases for PSNH and Yankee Gas were settled without significant issues, and the settlements allowed both entities to meet their respective financial objectives. However, the disappointing outcome of the CL&P rate case was below our range of expected results. In addition, CL&P was challenged during the year with poor responsiveness to customers’ concerns and issues. Senior management has since taken this issue as an opportunity to solidify NU’s commitment to meet its customers’ expectations. Under Mr. Shivery’s direction, management developed and implemented a multi-year communications strategy designed to communicate critical issues.

Mr. Shivery exceeded expectations with respect to NU’s New England energy policy initiatives. NU is actively involved in addressing regional energy reliability and environmental issues through Mr. Shivery’s initiative and is making outstanding contributions in this area. In addition, we have advanced the discussion regarding pursuit of potential energy solutions outside of NU’s geographical region with industry leaders and policymakers. Mr. Shivery also co-chairs the Edison Electricity Institute (EEI) Energy Delivery Committee, which has helped frame EEI positions around critical energy policy issues on a national and regional level.

Mr. Shivery met expectations relative to developing a longer-term strategic plan. He and his management team have identified emerging strategic opportunities which they are pursuing and have expanded their attention to enterprise risk management. In the third quarter, Mr. Shivery successfully hired a new officer as Senior Vice President – Enterprise Planning to further develop NU’s thinking about its future positioning and strategic opportunities.

Mr. Shivery continued to emphasize aligning the culture of the company to assure support of its strategic direction, performing above expectations in this goal area. Under Mr. Shivery’s direction, workforce plans were completed throughout the company and initiatives were implemented to address critical needs, including the introduction of business, financial and technical educational opportunities for NU employees. Mr. Shivery and the management team continued to improve safety, enhance diversity and effectively manage NU’s environmental responsibilities.

The Compensation Committee and the Corporate Governance Committee of NU’s Board of Trustees jointly considered Mr. Shivery’s performance on all of the individual performance goals set forth above. Coupled with NU’s overall corporate performance measured by ANI, the committee members applied judgment to determine their recommendation for Mr. Shivery’s annual incentive payment. In particular, the committees gave weight to the finding that NU’s total shareholder return in 2007 was in the top quartile of NU’s performance peer group of companies. Following a detailed review of these factors without Mr. Shivery present, the Board of Trustees awarded Mr. Shivery an annual incentive payment of $1,683,360 for 2007, consisting of $1,184,770 attributable to the achievement of 200% of the team goal and an additional $498,590 attributable to Mr. Shivery’s performance of his individual goals. The Board of Trustees determined that this annual incentive payment was consistent with Mr. Shivery’s above-expectations performance based on corporate, financial and individual criteria established for 2007. This amount also reflected an increase from the annual incentive payment received by Mr. Shivery for 2006, which the Board of Trustees believed was warranted in light of NU’s sustained strong corporate performance in 2007. Mr. Shivery’s annual incentive payment exceeds that of the other NEOs because of his significantly greater duties and responsibilities as NU’s chief executive officer.

Annual Incentive Payment for the Other NEOs

In addition to NU’s corporate ANI goal described above, the Compensation Committee considered individual performance goals and other factors in determining the annual incentive payments for each of the other NEOs. These factors included the annual incentive payment recommendations made by Mr. Shivery with respect to each of the NEOs and the scope of each NEO’s responsibilities, performance, and impact on or contribution to our corporate success and growth. The annual incentives paid to each NEO as described below include the maximum amount for the corporate ANI goal component.

The Compensation Committee determined that Mr. McHale and his organization made significant advancements strengthening NU’s enterprise risk management and financial organization capabilities and processes. Mr. McHale and his team successfully completed NU’s capital financing objectives for 2007 despite a difficult fixed-income market in the second half of the year, and maintained the current credit ratings and rating agency outlooks on NU and its four regulated utilities, despite increased capital expenditure projections. In addition, Mr. McHale’s organization played a critical role in rate cases for three of NU’s business units that, in the aggregate, produced results that were within NU’s anticipated range although the outcome of the CL&P rate case was below our range of expected results. Finally, Mr. McHale and his team were successful at reducing the market risk of NU’s competitive businesses while achieving above-budget net income. Based on his demonstrated leadership and this assessment of his successes, the Compensation Committee awarded Mr. McHale an annual incentive payment of $487,620 for 2007.

The Compensation Committee determined that Mr. Olivier and his team successfully completed important LNG storage, electric distribution, and electric transmission system projects and have made excellent progress on the New England East West Solution (NEEWS) major electric transmission system project. These projects will help position NU for the future and bring significant benefits to both customers and shareholders. In addition, Mr. Olivier’s team has improved system reliability. In 2007, NU’s transmission business very successfully completed a compliance audit conducted by the North American Electric Reliability Corporation. Based on his demonstrated leadership and this assessment of his successes, but acknowledging his shared responsibility for the CL&P rate case and customer service issues cited in the preceding description of Mr. Shivery’s award, the Compensation Committee awarded Mr. Olivier an annual incentive payment of $452,226 for 2007.

The Compensation Committee determined that Mr. Butler’s team advanced NU’s position on regional energy policy considerably in Connecticut, Massachusetts and New Hampshire, which will ultimately provide benefits to customers and shareholders. In addition, Mr. Butler’s team successfully communicated the need for additional revenues for three of NU’s companies, each of which conducted state regulatory ratemaking proceedings in 2007, although the outcome of the CL&P rate case was below NU’s range of expected results. Based upon these successes, but acknowledging his shared responsibility for the CL&P rate case and customer service issues cited in the preceding description of Mr. Shivery’s award, the Compensation Committee awarded Mr. Butler an annual incentive payment of $390,700 for 2007.

The Compensation Committee determined that Mr. Necci and his team improved system reliability and successfully completed important LNG storage and electric distribution system projects, which help position us for the future and bring significant benefits to both customers and shareholders. Based on his demonstrated leadership and this assessment of his successes, but acknowledging his shared responsibility for the CL&P rate case and customer service issues cited in the preceding description of Mr. Shivery’s award, the Compensation Committee awarded Mr. Necci an annual incentive payment of $208,660 for 2007.

Although Mrs. Grisé retired from NU during 2007, she was eligible to receive a prorated annual incentive payment for 2007. The Compensation Committee determined that Mrs. Grisé was successful in assisting NU in preparing for an orderly transition following her retirement and awarded Mrs. Grisé an annual incentive payment of $187,645 for 2007, representing an overall payout at target when adjusted for her term of employment during 2007.

2007 – 2009 LONG-TERM INCENTIVE PROGRAM

The Compensation Committee, acting jointly with the Corporate Governance Committee recommended to NU’s Board of Trustees a long-term incentive target grant value for Mr. Shivery as a percentage of base salary on the date of grant, which recommendation was approved by NU’s Board of Trustees. The Compensation Committee also approved long-term incentive target grant values for each of the other NEOs as a percentage of base salary on the date of grant. At target, each grant consisted of one-half RSUs and one-half performance cash, subject to adjustment by the Compensation Committee (except the Compensation Committee acts jointly with the Corporate Governance Committee in recommending to NU’s Board of Trustees adjustments to Mr. Shivery’s targets), reflecting the Committee’s desire to balance total shareholder return with NU’s corporate financial performance. In 2007, the Compensation Committee, acting jointly with the Corporate Governance Committee, recommended to NU’s Board of Trustees a long-term incentive compensation target for Mr. Shivery at 300% of base salary, which NU’s Board of Trustees approved. The Compensation Committee established long-term incentive compensation targets at 85% to 150% of base salary for the remaining NEOs. Mr. Olivier’s long-term incentive compensation target was

fixed at 125% of his base salary, which is below a target of 150% of base salary typically provided to executive officers at his level, because his compensation includes a special retirement benefit. Mrs. Grisé, who resigned as chief executive officer of CL&P effective January 15, 2007 and retired from NU effective July 1, 2007, did not participate in the 2007 – 2009 Long-Term Incentive Program.

Restricted Share Units (RSUs)

Each RSU awarded under the long-term incentive program entitles the holder to receive one NU common share at the time of vesting. All RSUs awarded in 2007 will vest in equal annual installments over three years. RSU holders are eligible to receive dividend equivalents on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU’s common shares. Dividend equivalents are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.

At the beginning of each year, the Compensation Committee determines target RSU awards for each participant in the long-term incentive program. Initially, the target RSU awards are equal to one-half of the long-term incentive compensation target for each participant. RSU awards are based on a percentage of base salary and measured in dollars. The aggregate dollar amount of the target RSU awards for all participants constitutes the target RSU Pool for that particular long-term incentive program. The Committee reserves the right to increase or decrease the target RSU Pool based on NU’s financial performance during the preceding fiscal year. In its discretion, the Committee may also increase or decrease RSU awards for individual participants based on the contribution by the executive officer to NU’s long-term strategic direction and the Committee’s assessment of the need to motivate the executive officer’s future performance. The Compensation Committee, acting jointly with the Corporate Governance Committee, recommends to NU’s Board of Trustees the final RSU award for Mr. Shivery. Based on input from Mr. Shivery, the Compensation Committee determines the final RSU awards for each of the other NEOs. Increases or decreases to target RSU awards for our executive officers will increase or decrease their compensation as compared to the compensation of executive officers of utilities listed in our customized peer group. Increases or decreases to individual target RSU awards will also correspondingly increase or decrease the RSU pool.

All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into NU common share equivalents by dividing the amount of each award by the average closing price for NU common shares during the last ten trading days in January in the year of the grant.

In 2007, the Committee approved a final RSU Pool for executive officers of NU System Companies, consisting of $5,340,525, which represents 146.5% of target, based on NU’s corporate performance during 2006 in connection with the increased focus on NU’s regulated utility businesses. The following RSU awards were approved, reflected as a percentage of target and in dollars, based on individual performance and contributions: Mr. Shivery: 175% ($2,625,000); Mr. McHale: 150% ($506,250); Mr. Olivier: 150% ($445,313); Mr. Necci: 110% ($139,715) and Mr. Butler: 130% ($377,918). The Committee did not grant RSU awards under the long-term incentive program to Mrs. Grisé, who retired from NU effective July 1, 2007.

RSU Design Changes

RSUs granted under the 2004 long-term incentive compensation program vest in equal installments on the grant-date anniversaries over four years. All RSUs granted under the 2005 and 2006 long-term incentive compensation programs vest in equal installments on the grant-date anniversaries over three years. Pursuant to the terms of the original RSU awards (except with respect to certain RSUs granted to Mr. Shivery), on each vesting date, NU distributed common shares to the RSU holders only with respect to one-half of the number of RSUs that vested. NU deferred the distribution of the remaining one-half of the common shares for an additional four years. Because RSU holders are taxed only upon the receipt of the underlying common shares, taxes on such remaining one-half of the common shares were also deferred for an additional four years. Pursuant to an agreement with Mr. Shivery, NU continues to defer the distribution of common shares upon the vesting of RSUs granted to him under the 2005, 2006 and 2007 programs until after he leaves NU. Except for RSUs granted to Mr. Shivery, the 2007 long-term incentive program did not contain automatic deferred distribution provisions.

In 2007, consistent with the adoption of share ownership guidelines (discussed below), the Compensation Committee amended the 2004, 2005 and 2006 long-term incentive compensation programs to eliminate the deferred distribution feature for executive officers, except for RSUs granted to Mr. Shivery under the 2004 program. The Committee also permitted executive officers to elect to continue deferred distribution of common shares upon vesting of RSUs granted under these programs. Executive officers who did not elect to continue deferred distribution received all common shares for which distribution had been previously deferred (in respect of RSUs that had previously vested) on February 25, 2008. In the future, executive officers who did not elect to continue deferred distribution will receive immediately all common shares distributable upon vesting of unvested RSUs, beginning with the February 25, 2008 vesting date. The elimination of the deferred distribution feature also resulted in the elimination of the ability to defer taxes for an additional four years.

All of the NEOs elected to continue deferred distribution of common shares upon vesting of RSUs granted under all of these programs except Mr. McHale, who elected to continue deferred distribution of common shares only for RSUs granted under the 2005 and 2006 programs. As a result, on February 25, 2008, NU distributed 1083 common shares to Mr. McHale and withheld 465 common shares to satisfy income tax withholding obligations in respect of previously vested RSUs granted under the 2004 long-term incentive program.

Share Ownership Guidelines

Effective in 2007, the Compensation Committee approved share ownership guidelines to emphasize the significance of increased share ownership by certain executive officers of NU and its subsidiaries. The Committee subsequently reviewed the guidelines for these executive officers and determined that they remain reasonable and require no modification. The guidelines call for Mr. Shivery, as Chief Executive Officer of NU, to own a minimum number of common shares valued at approximately six-times base salary, and the remaining executive officers to own a minimum number of NU common shares valued at approximately two to three-times base salary. The most prevalent share ownership level of Chief Executive Officers of utilities listed in our customized peer group was valued at approximately five-times base salary.


Executive Officer		Ownership Guidelines (Number of Shares)
CEO of NU		200,000
EVPs/SVPs of NU		45,000
Subsidiary presidents and key department heads		17,500

At the time the share ownership guidelines were implemented, the Committee required these executive officers to attain these ownership levels within five years. In 2007, the Committee amended the guidelines to require newly-hired executive officers to attain the ownership levels within seven years. All of our NEOs are currently at, or close to, these levels. Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs all satisfy the guidelines. Unexercised stock options do not count toward the ownership guidelines.

Performance Cash Program

General

The Performance Cash Program is a performance-based component of our long-term incentive program. Performance cash awards are equal to one-half of total individual long-term incentive awards at target. A new three-year program commences every year. Payment under a program depends on the extent to which NU achieves goals in the four metrics described below during each year of the program. The Compensation Committee determines the actual amounts payable, if any, only after the end of the final year in the respective program.

Cumulative Adjusted Net Income, which is consolidated NU net income adjusted to exclude the effects of certain nonrecurring income and expense items or events (which we defined as ANI under the annual incentive program) over the three years in a program.

Average adjusted ROE, which is the average of the annual ROE for NU for the three years in a program. The Committee adjusts average ROE on the same basis as cumulative adjusted net income.

Average credit rating of NU, which is the time-weighted average daily credit rating by the rating agencies Standard & Poor’s, Moody’s, and Fitch. The metric is calculated by assigning numerical values to credit ratings (A or A2: 5; A- or A3: 4; BBB+ or Baa1: 3; BBB or Baa2: 2; and BBB- or Baa3: 1) so that a high numerical value represents a high credit rating. In addition to average credit rating objectives, the ratings by S&P and Moody’s must remain above investment grade.

Relative total NU shareholder return as compared to the return of the utility companies listed in the performance peer group identified for each Performance Cash Program.

The Committee weighs each of the four metrics equally, reflecting the Compensation Committee’s belief that these areas are critical measurements of corporate success. The Committee measures NU’s cumulative adjusted net income, average adjusted ROE, and average credit rating because these metrics are directly related to NU’s multi-year business plan in effect at the beginning of the three-year program. The Committee also measures NU’s relative total shareholder return to emphasize to the plan participants the importance of achieving total shareholder returns at or above the median return for companies listed in the program performance peer group. NU is required to achieve a minimum level of performance under each metric before any amount is payable with respect to that metric. If NU achieves the minimum level of performance, then the resulting payout will equal 50% of the target. If NU achieves the maximum level of performance, then the resulting payout will equal 150% of target. The Committee fixed the minimum opportunity at 50% of target and the maximum opportunity at 150% of target because the Committee believes this range is consistent with the ranges used by companies listed in the program performance peer group.

2005 – 2007 Performance Cash Program

The Compensation Committee approved NU’s 2005 – 2007 Performance Cash Program in early 2005. Upon completion of NU’s fiscal year ended 2007, the Committee determined that NU achieved goals under each of the four metrics during the three-year program and, accordingly, that awards under the program were payable at an overall level of 130% of target. The table set forth below describes the goals under the 2005 – 2007 program and our actual results during that period:


2005 – 2007 Program Goals
Goal	Minimum	Target	Maximum	Actual Result
NU Cumulative Adjusted Net Income ($ in millions)	$ 519.5	$ 611.2	$ 702.9	$ 693.8
Average Adjusted ROE	6.3%	7.4%	8.5%	8.7%
Average Credit Rating	1.4	2.0	2.8	1.7
Relative Total Shareholder Return (percentile) (1)	40^th	60^th	80^th	91^st

(1)

The performance peer group for the 2005 – 2007 program included NU and the following companies: Consolidated Edison, Inc., DTE Energy Company, Energy East Corporation, Great Plains Energy Incorporated, Integrys Energy Group, Inc., NiSource, Inc., NSTAR, Pepco Holdings, Inc., PPL Corporation, Wisconsin Energy Corporation and Xcel Energy Inc.

Based on NU financial performance during the three-year performance period of the 2005 – 2007 Performance Cash Program, the Committee approved the following payments: Mr. Shivery: $1,365,000; Mr. McHale: $268,190; Mr. Olivier: $325,000; Mr. Necci $138,190, Mr. Butler: $341,250, and Mrs. Grisé: $434,958. The payments were determined pursuant to formulas set forth in the 2005 – 2007 Performance Cash Program and were not subject to the discretion of the Compensation Committee.

2007 – 2009 Performance Cash Program

The Committee approved NU’s 2007 – 2009 Performance Cash Program goals during early 2007. No amounts have been paid under this program, and the Committee will not determine whether any amounts are payable until the end of our 2009 fiscal year, which is the final year in the three-year program.

The 2007 – 2009 program also includes goals in four metrics: NU’s cumulative adjusted net income, NU’s average adjusted ROE, NU’s average credit rating, and NU’s relative total shareholder return. For the 2007 – 2009 program, cumulative adjusted net income and average adjusted ROE exclude the effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual IRS or regulatory issues; unexpected costs related to nuclear decommissioning; unexpected costs related to environmental remediation of the HWP; divestiture or discontinuance of a segment or component of NU’s business; mark-to-market impacts of agreements to which NU or any of its competitive subsidiaries are parties; unbudgeted charitable contributions; impairments on goodwill acquired before 2002 (more than five years prior to the beginning of this program cycle); and the impact of any settlement of, or final decision in, ongoing litigation with Con Edison.

The performance peer group for the 2007 – 2009 program includes NU and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., Consolidated Edison, Inc., Energy East Corporation, NiSource, Inc., NSTAR, Pepco Holdings, Inc., Pinnacle West Capital Corporation, Puget Energy, Inc., SCANA Corporation, Sierra Pacific Resources, Wisconsin Energy Corporation and Xcel Energy Inc.

SUPPLEMENTAL BENEFITS

NU provides a variety of basic and supplemental benefits designed to assist it in attracting and retaining executive officers for NU System Companies critical to its success by reflecting competitive practices. The Compensation Committee endeavors to adhere to a high level of propriety in managing executive benefits and perquisites. We do not provide permanent lodging or personal entertainment for any executive officer or employee, and our executive officers are eligible to participate in substantially the same health care and benefit programs available to our employees.

RETIREMENT BENEFITS

NU provides retirement income benefits for employees of NU System Companies, including officers, who commenced employment before 2006 under the Northeast Utilities Service Company Retirement Plan (Retirement Plan) and, for officers, under the SERP for Officers of Northeast Utilities System Companies (Supplemental Plan). Each plan is a defined benefit pension plan, which determines retirement benefits based on years of service, age at retirement, and "plan compensation." Plan compensation for the Retirement Plan, which is a qualified plan under the Internal Revenue Code, includes primarily base pay and non-officer annual incentives up to the Internal Revenue Code limits for qualified plans. Beginning in 2006, newly-hired exempt employees, including executive officers, participate in an enhanced defined contribution retirement plan, called the K-Vantage benefit, instead of the Retirement Plan. Employees hired before 2006 continue to participate in the Retirement Plan, except for those who elected to participate in the K-Vantage benefit.

The Supplemental Plan adds to plan compensation: base pay over the Internal Revenue Code limits; deferred base salary; annual executive incentive program awards; and, for certain participants, long-term incentive program awards, as explained in the narrative accompanying the Pension Benefits Table.

The Supplemental Plan consists of two parts. The first part, called the make-whole benefit, reimburses participants for benefits lost due to Internal Revenue Code limitations on benefits provided under the Retirement Plan. The second part, called the target benefit, is available to all NEOs except Messrs. Olivier and Necci. The target benefit supplements the Retirement Plan and make-whole benefit under the Supplemental Plan so that, upon attaining at least 25 years of service, total retirement benefits from these plans will equal a target percentage of the final average compensation. To receive the target benefit, a participant must remain employed by NU or its subsidiaries at least until age 60, unless NU’s Board of Trustees establishes a lower age.

The value of the target benefit was reduced in 2005 to reflect changes in competitive practices, which indicated general reductions in the prevalence of defined benefit plans and the value of special retirement benefits to senior executives. Individuals who began serving as officers before February 2005 are eligible to receive a target benefit with the target percentage fixed at 60%. Individuals who began serving as officers from and after February 2005 are eligible to receive a target benefit with the target percentage fixed at 50%. As a result, Messrs. Shivery and Butler have target benefits at 60% while Mr. McHale has a target benefit at 50%.

Mr. Shivery’s employment agreement provides for a special total retirement benefit determined using the Supplemental Plan target benefit formula plus three additional years of company service. This benefit will be reduced by two percent per year for each year Mr. Shivery retires before age 65. Upon retirement, Mr. Shivery will be eligible to receive the cash value of retirement health benefits. See the Pension Benefits Table and the accompanying narrative for more details of these arrangements.

NU entered into an employment agreement with Mr. Olivier that includes retirement benefits similar to the benefits provided by his previous employer. Accordingly, Mr. Olivier is entitled to receive separate retirement benefits in lieu of the Supplemental Plan benefits described above. Pursuant to his agreement, Mr. Olivier will receive a targeted pension value if he meets certain eligibility requirements. See the Pension Benefits Table and the accompanying narrative for more details of this arrangement. As discussed under the caption entitled Mix of Compensation Elements above, Mr. Olivier’s long-term incentive plan targets and termination benefits are less than those provided to other similarly situated officers because of these separate retirement benefits.

401K PLAN

NU provides an opportunity for employees to save money for retirement on a tax-favored basis through the Northeast Utilities Service Company 401k Plan (401k Plan). The 401k Plan is a defined contribution plan under Section 401(k) of the Internal Revenue Code. Participants with at least six months of service receive employer matching contributions, not to exceed 3% of base compensation, one-third of which are in cash available for investment in various mutual fund alternatives and two-thirds of which are in the form of NU common shares (ESOP shares).

The K-Vantage benefit provides for employer contributions to the 401k Plan in amounts between 2.5% and 6.5% of plan compensation based on age and years of service. These contributions are in addition to employer matching contributions. Executive officers hired beginning in 2006 also participate in a companion nonqualified K-Vantage benefit that provides defined contribution benefits above Internal Revenue Code limits on qualified plans.

NONQUALIFIED DEFERRED COMPENSATION PLAN

Our executive officers participate in a Nonqualified Deferred Compensation Plan (Deferral Plan) to provide additional retirement benefits not available in the 401k Plan because of Internal Revenue Code limits on qualified plans. Under the Deferral Plan, executive officers are entitled to defer up to 100% of base salary and annual incentive awards. NU matches officer deferrals in an amount equal to 3% of the amount of base salary above Internal Revenue Code limits on qualified plans. The match is deemed to be invested in NU common shares and vests at the end of the third year after the calendar year in which the match was earned, or at retirement, whichever occurs first. Participants are entitled to select deemed investments for all deferred amounts from the same investments available in the 401k Plan. NU also credits the Deferral Plan in amounts equal to the K-Vantage benefit that would have been provided under the 401k Plan but for Internal Revenue Code limits on qualified plans. This nonqualified plan is unfunded. Please see the Nonqualified Deferred Compensation Table and the accompanying notes for additional plan details.

PERQUISITES

It is our philosophy and the philosophy of NU that perquisites should be provided to executive officers as needed for business reasons, and not simply in reaction to prevalent market practices.

With the exception of Mr. Necci, senior executive officers, including the other NEOs, are eligible to receive reimbursement for financial planning and tax preparation services. This benefit is intended to help ensure that executive officers seek competent tax advice, better prepare complex tax returns, and leverage the value of our compensation programs. Reimbursement is limited to $4,000 every two years for financial planning services and $1,500 per year for tax preparation services.

All executive officers receive a special annual physical examination benefit to help ensure serious health issues are detected early. The benefit is limited to the reimbursement of up to $500 for fees incurred beyond those covered by our medical plan.

When hiring a new executive officer, NU sometimes reimburses executive officers for certain temporary living and relocation expenses, or provides a lump sum payment in lieu of specific reimbursement. These expenses are grossed-up for income taxes attributable to such reimbursements.

When required for a valid business purpose, an executive officer may be accompanied by his or her spouse, in which case NU will reimburse the executive officer for all spousal travel expenses, including a gross-up for taxes.

Tax gross-ups are provided as described above only because of the direct corporate benefit to us when executive officers incur such expenses. The impact of the aggregate amount of the tax gross-ups is not material to us.

CONTRACTUAL AGREEMENTS

NU has entered into employment agreements with certain executive officers, including Messrs. Shivery, McHale, Olivier and Butler. The agreements specify compensation and benefits during the employment term and include benefits payable upon involuntary termination of employment and termination of employment following a change of control. We believe that these benefits are necessary to attract and retain competent and capable executive talent. We also believe that these benefits help to ensure our executive officers’ continued dedication and objectivity at a time when they might otherwise be concerned about their future employment.

In the event of a change of control, the agreements provide for enhanced cash severance benefits following termination of employment without "cause" (as defined in the employment agreement, generally involving a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to NU property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement) or upon termination of employment by the executive for "good reason" (as defined in the employment agreement, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control). The Compensation Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance.

As defined in the employment agreements with Messrs. Shivery, McHale and Butler, a "change of control" means a change in ownership or control effected through (i) the acquisition of 20% or more of the combined voting power of NU common shares or other voting securities, (ii) a change in the majority of NU’s Board of Trustees over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding NU common shares immediately prior to such business combination do not beneficially own more than 50% of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than to an entity with respect to which following completion of the transaction more than 50% of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.

Pursuant to the change of control provisions in the employment agreements, each NEO except for Messrs. Olivier and Necci will be reimbursed for the full amount of any excise taxes imposed on severance payments and any other payments under Section 4999 of the Internal Revenue Code. This "gross-up" is intended to preserve the aggregate amount of the severance payments by compensating the executive officers for any adverse tax consequences to which they may become subject under the Internal Revenue Code. The mechanics and impact of the termination arrangements in the employment agreements are described in more detail in the Potential Payments Upon Termination or Change of Control Tables, appearing further below. Severance payments to Messrs. Olivier and Necci may be reduced to avoid excise taxes.

To help protect us after the termination of an executive officer’s employment, the employment agreements include non-competition and non-solicitation covenants pursuant to which the executive officers have agreed not to compete with NU or its subsidiaries, or solicit NU employees for a period of two years (one year for Messrs. Olivier and Necci) after termination of employment.

In the event of termination of employment without "cause" or upon termination of employment by an NEO for good reason, in each case following a change of control, the expiration date of all vested unexercised stock options held by our NEOs will be extended automatically for up to an additional 36 months, but not beyond the original expiration date, to provide these holders with an opportunity to benefit from increased shareholder value created by the change of control. Also, in the event of a change of control, the long-term incentive programs provide for the vesting, pro rata based on the number of days of employment during the performance period, and payment at target of performance cash, whether or not the executive’s employment terminates, unless the Committee determines otherwise.

Finally, in the event of a change of control, the Nonqualified Deferred Compensation Plan provides for the immediate vesting of any employer matches, although these matches will be paid according to the schedule defined by the executive’s original election.

As discussed under the caption entitled Supplemental Benefits above, our employment agreements with Messrs. Shivery and Olivier also include additional retirement benefits.

Mrs. Grisé resigned as chief executive officer of CL&P effective January 15, 2007 and retired from NU on July 1, 2007. At the time of her retirement, Mrs. Grisé affirmed the negative covenants under her employment agreement, including her agreement, for two years following her retirement, to refrain from engaging in activities on behalf of certain competitors, soliciting certain employees or interfering with NU’s business relationships. In consideration of these covenants, NU agreed to provide Mrs. Grisé with a special retirement benefit which, when combined with her annual benefit under the Retirement Plan and the Supplemental Plan, and based on her annuity elections, will result in an annual payment of $618,681. On January 2, 2008, NU paid Mrs. Grisé a lump sum cash payment of $120,535 (i) as consideration for a standard general release of all claims against NU in connection with her employment, which she delivered to NU upon her retirement, and (ii) in lieu of a grant of RSUs and/or performance cash under the 2007-2009 Long-Term Incentive Program.

TAX AND ACCOUNTING CONSIDERATIONS

Tax Considerations. All executive compensation for 2007 was fully deductible by NU for federal income tax purposes, except for approximately $465,000 in RSU distributions to Mr. Shivery.

Section 162(m) of the Internal Revenue Code limits the tax deduction for compensation paid to a company’s Chief Executive Officer and certain other executives. NU is entitled to deduct compensation payments above $1 million as compensation expense only to the extent that these payments are "performance based" in accordance with Section 162(m) of the Internal Revenue Code. NU’s annual incentive program and performance cash program qualify as performance-based compensation under the Internal Revenue Code. As required by Section 162(m), the Compensation Committee reports to the Board of Trustees annually the extent to which various performance goals have been achieved. RSUs do not qualify as performance-based compensation.

Currently, Mr. Shivery is the only NEO to exceed the Section 162(m) limit. To preserve an employee compensation tax deduction for NU, Mr. Shivery agreed, for as long as it is beneficial to NU, to defer the distribution to him of common shares in respect of all vested RSUs,

which will begin in the calendar year after he leaves NU, at which time Section 162(m) will no longer apply to him. The non-deductible RSU gains for Mr. Shivery in 2007 described above relate to RSU awards granted before Mr. Shivery was elected as NU’s Chief Executive Officer.

Section 409A of the Internal Revenue Code provides that amounts deferred under nonqualified deferred compensation plans are includable in an employee’s income when vested unless certain requirements are met. If these requirements are not met, employees are also subject to additional income tax and interest penalties. All of NU’s supplemental retirement plans, severance arrangements, and other nonqualified deferred compensation plans currently meet, or will be amended to meet, these requirements. As a result, employees will be taxed when the deferred compensation is actually paid to them. NU will be entitled to a tax deduction at that time.

Section 280G of the Internal Revenue Code disallows a tax deduction for "excess parachute payments" in connection with the termination of employment related to a change of control (as defined in the Internal Revenue Code), and Section 4999 of the Internal Revenue Code imposes a 20% excise tax on any person who receives excess parachute payments. As discussed above, our NEOs are entitled to receive certain payments upon termination of their employment, including termination following a change of control. Under the terms of the agreements, all NEOs except Messrs. Olivier and Necci are entitled to receive tax gross-ups for any payments that constitute an excess parachute payment. Accordingly, NU’s tax deduction would be disallowed under Section 280G for all excess parachute payments as well as tax gross-ups. Not all of the payments to which NEOs are entitled are excess parachute payments. The amounts of the payments that constitute excess parachute payments are set forth in the tables found under the caption entitled Potential Payments at Termination or Change of Control, below.

In the event of a change of control in which NU is not the surviving entity, RSU awards granted to executive officers provide that the acquirer will assume or replace the awards, even if the executive remains employed after the change of control.

Accounting Considerations. RSUs disclosed in the Grants of Plan-Based Awards Table are accounted for based on their grant date fair value, as determined under Statement of Financial Accounting Standards (SFAS) No. 123(R), which is recognized over the service period, or the three-year vesting period applicable to the RSUs. Assumptions used in the calculation of this amount appear under the caption entitled Management’s Discussion and Analysis and Results of Operations in our Annual Report to Shareholders, filed as an exhibit to our Annual Report on Form 10-K for the fiscal year ended December 31, 2007. Forfeitures are estimated, and the compensation cost of the awards will be reversed if the employee does not remain employed by NU throughout the three-year vesting period. Performance cash program payments are accounted for on a variable basis based on the most likely payment outcome.

COMPENSATION COMMITTEE REPORT

The Compensation Committee of the NU Board of Trustees (Compensation Committee) has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with CL&P management. Based on this review and discussion the Compensation Committee has recommended to the Board of Directors of CL&P that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

The Compensation Committee

E. Gail de Planque, Chair

Robert E. Patricelli, Vice Chair

Richard R. Booth

Cotton M. Cleveland

Sanford Cloud, Jr.

James F. Cordes

Elizabeth T. Kennan

Dated: February 12, 2008

SUMMARY COMPENSATION TABLE

The table below summarizes the total compensation paid or earned by our Chief Executive Officer, Mr. Olivier, our Senior Vice President and Chief Financial Officer, Mr. McHale, and the three other most highly compensated executive officers other than Mr. Olivier and Mr. McHale who were serving as executive officers at the end of 2007, including Mr. Shivery, the Chief Executive Officer of NU and our Chairman, and one former executive officer who would have been among the three other most highly compensated executive officers had she been serving as an executive officer at the end of 2007 (collectively, the Named Executive Officers or NEOs). As explained in the footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on his or her behalf for the fiscal year ended December 31, 2007. The compensation shown for each executive officer was for all services in all capacities to NU and its subsidiaries. All salaries, annual incentive amounts and long-term incentive amounts paid to these executive officers were paid by Northeast Utilities Service Company, a service company subsidiary of NU.


Name and Principal Position	Year	Salary ($) (1)	Bonus ($) (2)	Stock Awards ($) (3)	Option Awards ($) (4)	Non-Equity Incentive Plan Compensation ($) (5)	Change in Pension Value and Non-Qualified Deferred Compensation Earnings ($) (6)	All Other Compensation ($) (7)	Total ($)
Charles W. Shivery	2007	987,308	--	1,779,313	--	3,048,360	1,326,931	49,026	7,190,938
Chairman	2006	918,846	--	1,061,205	--	1,698,395	1,274,011	40,691	4,993,148

David R. McHale	2007	434,135	--	296,891	--	755,810	614,481	7,603	2,108,920
Senior Vice President and Chief Financial Officer	2006	353,847	--	148,512	--	395,693	413,275	6,600	1,317,927

Leon J. Olivier	2007	462,096	--	306,115	--	777,226	251,556	15,042	1,812,035
Chief Executive Officer	2006	411,039	--	178,951	--	451,419	275,264	13,692	1,330,365

Raymond P. Necci	2007	295,846	--	129,195	--	346,850	1,460,754	9,299	2,241,944
President and Chief Operating Officer CL&P and Yankee Gas	2006	282,589	--	103,307	--	200,229	191,963	8,898	786,986

Gregory B. Butler	2007	382,244	--	319,716	--	731,950	195,321	12,941	1,642,172
Senior Vice President and General Counsel	2006	359,659	--	218,078	--	383,279	215,642	7,077	1,183,735

Cheryl W. Grisé	2007	354,671	--	200,900	--	622,604	2,059,805	8,994	3,246,974
Former Chief Executive Officer CL&P (8)	2006	532,295	--	494,672	--	530,613	479,176	16,396	2,053,152

(1)

Includes amounts deferred by the Named Executive Officers under the Deferral Plan, as follows: Mr. Shivery: $29,619; Mr. Olivier: $124,766; Mr. Necci: $44,377; Mr. Butler: $3,822; and Mrs. Grisé: $5,774. For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.

(2)

No discretionary bonus awards were made to any of the Named Executive Officers in the fiscal year ended December 31, 2007.

(3)

Reflects the dollar amounts recognized for financial statement reporting purposes for the fiscal year ended December 31, 2007, in accordance with the treatment of time-based RSU and restricted share grants under generally accepted accounting principles. The amounts reflect the accounting expense of shares granted in and prior to 2007. Assumptions used in the calculation of this amount appear under the caption entitled Management’s Discussion and Analysis and Results of Operations in our annual report to shareholders for the fiscal year ended December 31, 2007.

In 2005, 2006 and 2007, the Named Executive Officers were granted RSUs that vest in equal annual installments over three years as long-term incentive compensation except for Mrs. Grisé, who was not granted RSUs in 2007. Pursuant to the long-term

incentive programs approved in 2007, subject to the officer’s election in December 2007 to continue the automatic four-year deferral of one-half of RSUs that vest on a particular date, NU distributes common shares upon the vesting of RSUs, except with respect to RSUs granted to Mr. Shivery. NU defers the distribution of common shares upon vesting of RSUs granted to Mr. Shivery, which will begin in the calendar year after he leaves NU. RSU holders are eligible to receive dividend equivalents on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares. Dividend equivalents are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.

In 2004, the Named Executive Officers were granted RSUs that vest in equal annual installments over four years as long-term incentive compensation. Pursuant to amendments to the long-term incentive programs approved in 2007, subject to the officer’s election in December 2007 to continue the automatic four-year deferral of one-half of RSUs as they vest under the 2004 Program, NU distributes common shares with respect to RSUs upon vesting. Also in 2004, Mr. Shivery and Mrs. Grisé were granted RSUs that vest in equal annual installments over three years as partial payment of their awards under the 2003 Annual Incentive Program. In addition, upon his appointment as NU’s Chairman, President and Chief Executive Officer in 2004, Mr. Shivery was granted 25,000 restricted shares that vest in equal annual installments over four years. NU pays dividends on these restricted shares during the vesting period to the same extent that dividends are declared and paid on NU common shares.

In 2003, the Named Executive Officers were granted restricted shares that vest in equal annual installments over four years as long-term incentive compensation. NU pays dividends on these restricted shares during the vesting period to the same extent that dividends are declared and paid on NU common shares. In connection with her retirement on July 1, 2007, unvested RSUs held by Mrs. Grisé that would have vested on February 25, 2008, instead vested in proportion to the time she was employed with us after February 25, 2006. Additional information regarding Mrs. Grisé's retirement is available in the Post-Employment Compensation Table prepared for Mrs. Grisé.

(4)

NU has not granted any stock options since 2002. Accordingly, NU did not grant stock options to any of the Named Executive Officers in 2007.

(5)

Includes payments to the Named Executive Officers under the 2007 Annual Incentive Program (Mr. Shivery: $1,683,360; Mr. McHale: $487,620; Mr. Olivier: $452,226; Mr. Necci: $208,660; and Mr. Butler: $390,700). Also includes payments under the 2005 – 2007 Long-Term Incentive Program (Mr. Shivery: $1,365,000; Mr. McHale: $268,190; Mr. Olivier: $325,000; Mr. Necci: $138,190; Mr. Butler: $341,250; and Mrs. Grisé: $434,958). Performance goals under the 2007 Annual Incentive Program were communicated to each officer by Mr. Shivery or, in the case of Mr. Shivery, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2007. The Compensation Committee, acting jointly with the Corporate Governance Committee, determined the extent to which these goals were satisfied (based on input from Mr. Shivery, in the case of the other NEOs) in February 2008. Performance goals under the 2005 – 2007 Long-Term Incentive Program were communicated to each officer by Mr. Shivery or, in the case of Mr. Shivery, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2005. The Compensation Committee determined the extent to which the long-term goals were satisfied in February 2008.

(6)

Includes the actuarial increase in the present value from December 31, 2006 to December 31, 2007 of the Named Executive Officer’s accumulated benefits under all of NU’s pension plans determined using interest rate and mortality rate assumptions consistent with those appearing under the caption entitled Management’s Discussion and Analysis and Results of Operations in our annual report to shareholders for the fiscal year ended December 31, 2007. The Named Executive Officer may not be fully vested in such amounts. The change in pension value for Mr. Necci increased significantly in 2007, when his age made him eligible for early retirement under NU’s pension plans. More information on this topic is set forth in the notes to the Pension Benefits table, appearing further below. There were no above-market earnings on deferrals in 2007.

Mrs. Grisé retired on July 1, 2007 and began receiving her qualified pension. See Post-Employment Compensation: Cheryl W. Grisé for a summary of payments to Mrs. Grisé.

(7)

Includes matching contributions of $6,750 allocated by NU to the account of each of the Named Executive Officers under the 401k Plan and employer matching contributions under the Deferral Plan for the Named Executive Officers who deferred part of their salary in the fiscal year ended December 31, 2007 (Mr. Shivery: $22,869; Mr. Olivier: $7,113; Mr. Necci: $2,125; Mr. Butler: $4,717; and Mrs. Grisé: $1,911), plus tax gross-ups (Mr. Shivery: $7,455; Mr. Olivier: $1,155; Mr. Necci: $424; Mr. Butler: $1,474; and Mrs. Grisé: $333). Mr. McHale did not participate in the Deferred Compensation Plan. Also includes perquisites received by Mr. Shivery in the amount of $11,952 consisting of reimbursement of spousal travel expenses and a cell phone allowance.

(8)

In connection with her retirement on July 1, 2007, on January 2, 2008, NU paid Mrs. Grisé a lump sum cash payment of $120,535 (i) as consideration for a standard general release of all claims against NU in connection with her employment, which she delivered to NU upon her retirement, and (ii) in lieu of a grant of RSUs and/or performance cash under the 2007-2009 long-term incentive program. This amount included interest accrued from July 1, 2007 through January 2, 2008. Additional information is set forth in the Post-Employment Compensation Table prepared for Mrs. Grisé.

GRANTS OF PLAN-BASED AWARDS DURING 2007

The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2007. The table also discloses the underlying stock awards and the grant date for equity-based awards. NU has not granted any stock options since 2002. Accordingly, NU did not grant stock options to any of the Named Executive Officers in 2007.


Name	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares of Stock or Units (#) (3)	Grant Date Fair Value of Stock and Option Awards ($) (4)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)		Grant Date Fair Value of Stock and Option Awards ($) (4)
Charles W. Shivery
Annual Incentive (1)	2/13/2007	493,654	987,308	1,974,616	n/a	n/a
Long-Term Incentive (2)	2/13/2007	750,000	1,500,000	2,250,000	95,316	2,625,003

David R. McHale
Annual Incentive (1)	2/13/2007	141,094	282,188	564,376	n/a	n/a
Long-Term Incentive (2)	2/13/2007	168,750	337,500	506,250	18,382	506,240

Leon J. Olivier
Annual Incentive (1)	2/13/2007	150,181	300,362	600,724	n/a	n/a
Long-Term Incentive (2)	2/13/2007	148,450	296,900	445,350	16,170	445,322

Raymond P. Necci
Annual Incentive (1)	2/13/2007	73,962	147,923	295,846	n/a	n/a
Long-Term Incentive (2)	2/13/2007	63,500	127,000	190,500	5,073	139,710

Gregory B. Butler
Annual Incentive (1)	2/13/2007	124,229	248,458	496,916	n/a	n/a
Long-Term Incentive (2)	2/13/2007	145,350	290,700	436,050	13,723	377,931

Cheryl W. Grisé
Annual Incentive (1)	2/13/2007	93,823	187,645	187,645	n/a	n/a
Long-Term Incentive (2)(5)	2/13/2007	--	--	--	--	--

(1)

Amounts reflect the range of potential payouts, if any, under the 2007 Annual Incentive Program for each Named Executive Officer, as described in the Compensation Discussion and Analysis. The payment in 2008 for performance in 2007 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. The threshold payment under the Annual Incentive Program is 50% of target. However, based on Adjusted Net Income and individual performance, the actual payment under the Annual Incentive Program could be zero.

(2)

Reflects the range of potential payouts, if any, pursuant to performance cash awards under the 2007 - 2009 Long-Term Incentive Program, as described in the Compensation Discussion and Analysis. Grants of three-year performance cash awards were made to officers during 2007 under the 2007 – 2009 Long-Term Incentive Program. Performance cash will be fully vested at the end of the performance period and paid in cash to the officer during the first fiscal quarter after the end of the performance period.

(3)

Reflects the number of RSUs granted to each of the Named Executive Officers on February 13, 2007 under the 2007 – 2009 Long-Term Incentive Program. The RSUs will vest in equal installments on February 25, 2009, 2010 and 2011. Except for Mr. Shivery, NU will distribute NU common shares in respect of vested RSUs on a one-for-one basis immediately upon vesting

after reduction for applicable withholding taxes. For Mr. Shivery, NU will distribute common shares, after reduction for applicable withholding taxes, in respect of vested RSUs in three approximately equal annual installments beginning the later of (i) six months after he leaves NU and (ii) January of the calendar year following the year in which he leaves NU. RSU holders are eligible to receive dividend equivalents on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares. Dividend equivalents are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs. The Annual Incentive program does not have an equity component.

(4)

Reflects the grant-date fair value of RSUs granted to the Named Executive Officers on February 13, 2007, under the 2007 – 2009 Long-Term Incentive Program determined pursuant to generally accepted accounting principles. The Annual Incentive program does not have an equity component.

(5)

NU did not grant RSUs to Mrs. Grisé in 2007 because she had previously announced her intention to retire on July 1, 2007. Additional information is set forth in the Post-Employment Compensation Table prepared for Mrs. Grisé.

EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2007

The following table sets forth option, restricted share and RSU grants outstanding at the end of our fiscal year ended December 31, 2007 for each of the Named Executive Officers. All outstanding options were fully vested as of December 31, 2007.


	Option Awards (1)				Stock Awards
Name		Number of Securities Underlying Unexercised Options Exercisable (#)	Option Exercise Price ($)	Option Expiration Date		Number of Shares or Units that have not Vested (#)(2)	Market Value of Shares or Units of Stock that have not Vested ($)(3)
Charles W. Shivery		29,024	18.90	06/11/2012		180,987	5,666,706
David R. McHale		--				31,621	990,058
Leon J. Olivier		--				30,768	963,359
Raymond P. Necci		--				12,121	379,502
Gregory B. Butler		--				30,368	950,833
Cheryl W. Grisé (4)		--				6,523	204,239

(1)

NU has not granted stock options since 2002.

(2)

An aggregate of 140,581 unvested RSUs vested on February 25, 2008 (Mr. Shivery: 87,901; Mr. McHale: 14,484; Mr. Olivier: 15,281; Mr. Necci: 6,581 and Mr. Butler: 16,334). An additional 94,444 unvested RSUs will vest on February 25, 2009 (Mr. Shivery: 60,489; Mr. McHale: 10,852; Mr. Olivier: 9,957; Mr. Necci: 3,805 and Mr. Butler: 9,341). An additional 50,842 unvested RSUs will vest on February 25, 2010 (Mr. Shivery: 32,597; Mr. McHale: 6,286; Mr. Olivier: 5,530; Mr. Necci: 1,735 and Mr. Butler: 4,693).

(3)

The market value of RSUs is determined by multiplying the number of share units by $31.31, the closing price per share of NU common shares on December 31, 2007, the last trading day of the fiscal year.

(4)

All of the unvested RSUs held by Mrs. Grisé vested on January 2, 2008. NU distributed common shares, net of taxes, to Mrs. Grisé in respect of these RSUs.

OPTIONS EXERCISED AND STOCK VESTED IN 2007

The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2007. In 2007, Messrs. McHale, Olivier and Necci, and Mrs. Grisé exercised options. The Stock Awards columns report the vesting of restricted share grants and RSU grants to the Named Executive Officers in February 2007.


	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($) (1)	Number of Shares Acquired on Vesting (#) (2)	Value Realized on Vesting ($) (3)
Charles W. Shivery	--	--	61,324	1,821,947
David R. McHale	7,500	59,841	9,119	270,922
Leon J. Olivier	19,900	261,120	10,892	323,610
Raymond P. Necci	23,500	247,363	5,909	175,552
Gregory B. Butler	--	--	13,292	394,905
Cheryl W. Grisé	171,228	2,321,646	29,882	887,784

(1)

Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price on the date of exercise.

(2)

Includes common shares distributed in respect of special grants of RSUs to Mr. Shivery (3,371 shares) and Mrs. Grisé (5,570 shares) during 2004 in connection with awards under the 2003 Annual Incentive Program. Also includes 6,250 restricted shares granted to Mr. Shivery upon his appointment as NU’s Chairman, President and Chief Executive Officer in 2004, for which restrictions lapsed during 2007.

Also includes awards granted to our Named Executive Officers under our long-term incentive programs, as follows:


Name	2003 Program	2004 Program	2005 Program	2006 Program
Charles W. Shivery	10,140	5,748	14,879	27,186
David R. McHale	1,130	1,006	2,533	4,450
Leon J. Olivier	1,388	1,174	4,015	4,315
Raymond P. Necci	1,185	1,000	1,706	2,018
Gregory B. Butler	1,945	3,592	3,224	4,529
Cheryl W. Grisé	5,746	5,568	6,068	6,930

In all cases, NU reduces the distribution of common shares by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount NU distributes in cash. Included in the value realized are values associated with deferred RSUs, which are also reported in the Registrant Contributions in Last Fiscal Year column of the Non-Qualified Deferred Compensation Table.

(3)

Value realized is based on $29.71 per share, the closing price of common shares on February 23, 2007. This value includes the value of vested RSUs for which the distribution of common shares is currently deferred.

PENSION BENEFITS IN 2007

The Pension Benefits Table sets forth the estimated present value of accumulated retirement benefits that would be payable to each Named Executive Officer, except for Mrs. Grisé, upon his retirement as of the first date upon which he is eligible to receive an unreduced pension benefit (see below). The table distinguishes the benefits among those available through the Retirement Plan, the Supplemental Plan and any additional benefits available under the respective officer’s employment agreement. The Supplemental Plan provides a make whole benefit that is based in part on compensation that is not permitted to be recognized under a tax-qualified plan and provides a target benefit if the eligible officer continues his employment until age 60. Benefits under the Supplemental Plan are also based on elements of compensation that are not included under the Retirement Plan. This includes compensation equal to: (i) deferred compensation; (ii) the value of awards under the Annual Incentive Program for officers; and (iii) long-term incentive awards only for Messrs. McHale and Butler (as to each of their respective make whole benefits) and Mrs. Grisé (as to her target benefit), the values of which are frozen at the 2001 target levels.

The present value of accumulated benefits shown in the Pension Benefits Table was calculated as of December 31, 2007 assuming benefits would be paid in the form of a 50% contingent annuitant option (the typical form of payment for the target benefit), except for Mrs. Grisé, who chose the 75% contingent annuitant option upon her retirement. For Mr. Olivier, who has a special retirement arrangement, we assumed that his special retirement benefit would be paid as a lump sum, and his Retirement Plan benefit would be paid in the form of a 33.33% contingent annuitant option (the typical form of payment under the Retirement Plan). For Mr. Necci, we assumed all benefits would be paid in the form of a 33.33% contingent annuitant option (the typical form of payment under the Retirement Plan). For this table, we assumed that none of Mr. Olivier’s benefits are provided under the Supplemental Plan. In addition, the present value of accrued benefits for any Named Executive Officer assumes that benefits commence at the earliest age at which the participant would be eligible to retire and receive unreduced benefits. Named Executive Officers are eligible to receive unreduced benefits upon the earlier of (a) attainment of age 65 or (b) attainment of at least age 55 when age plus service equals 85 or more years, except for Mr. Olivier. Mr. Olivier’s unreduced benefit is available at age 60 pursuant to his employment agreement. The target benefit is available for Messrs. Butler and McHale only after age 60. Accordingly, Mr. Shivery is eligible to receive unreduced benefits at age 65, Messrs. McHale and Olivier are eligible to receive unreduced benefits at age 60 and Mr. Butler is eligible to receive unreduced benefits at age 62. Mr. Necci became eligible to receive unreduced benefits at age 55 and is currently eligible to retire.

The limitations applicable to the Retirement Plan under the Internal Revenue Code as of December 31, 2007 were used to determine the benefits under each plan. The accrued benefits reflect actual compensation (both salary and incentives) earned during 2007. Under the terms of the Supplemental Plan, annual incentives earned for services provided in a plan year are deemed to have been paid rateably over that plan year. For example, the March 2008 payment pursuant to the 2007 annual incentive program was reflected in the 2007 plan compensation. We determined the present value of the benefit at retirement age by using the discount rate of 6.60% under SFAS No. 87 for the 2007 fiscal year end measurement (as of December 31, 2007). This present value assumes no pre-retirement mortality, turnover or disability. However, for the postretirement period beginning at the retirement age, we used the RP2000 Combined Healthy mortality table as published by the Society of Actuaries (same table used for financial reporting under FAS 87). Additional assumptions appear under the caption entitled Management’s Discussion and Analysis and Results of Operations in our annual report to shareholders for the fiscal year ended December 31, 2007.

Pension Benefits


Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($)	Payments During Last Fiscal Year ($)
Charles W. Shivery (1)	Qualified Plan	5.6	144,671	--
	Supplemental Plan	5.6	2,595,104	--
	Other Special Benefit	8.6	1,472,337	--
David R. McHale	Qualified Plan	26.3	399,757	--
David R. McHale	Supplemental Plan	26.3	1,386,262	--
Leon J. Olivier (2)	Qualified Plan	8.8	260,225	--
	Supplemental Plan	6.3	--	--
	Other Special Benefit	6.3	1,428,663	--
	Other Special Benefit	32.3	1,241,765	105,966
Raymond P. Necci	Qualified Plan	31.3	1,150,052	--
Raymond P. Necci	Supplemental Plan	31.3	1,354,069	--
Gregory B. Butler	Qualified Plan	11.0	171,856	--
Gregory B. Butler	Supplemental Plan	11.0	821,985	--
Cheryl W. Grisé (3)	Qualified Plan	26.9	747,040	28,525
Cheryl W. Grisé (3)	Supplemental Plan	26.9	7,635,240	--

(1)

Mr. Shivery’s actual service with NU totaled 5.6 years at December 31, 2007. However, Mr. Shivery’s employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between: (i) the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three years to his actual service and using an early retirement commencement reduction factor of two percent per year for each year Mr. Shivery’s age upon retirement is under age 65, if that factor yields a more favorable result to Mr. Shivery than the factors then in use under the Retirement Plan, and (ii) benefits otherwise payable from the Retirement Plan and the Supplemental Plan. The value of the additional three years of service on December 31, 2007 was approximately $1,472,337.

(2)

Mr. Olivier was employed with Northeast Nuclear Energy Company (NNECO), one of our affiliates, from October of 1998 through March of 2001. In connection with this employment, he received a special retirement benefit that provided credit for service with NNECO when calculating the value of his defined benefit pension, offset by the pension benefit provided by NNECO. The benefit, which commenced upon Mr. Olivier’s 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit. The present value of future payments under this benefit was calculated using the actuarial assumptions currently used by the Retirement Plan. Mr. Olivier was rehired by NU in September 2001. Mr. Olivier’s current employment agreement provides for certain supplemental pension benefits in lieu of benefits under the Supplemental Plan if certain eligibility requirements are met, in order to provide a benefit similar to that provided by NNECO. Under this arrangement, if Mr. Olivier remains continuously employed by NU until September 10, 2011 (or terminates his employment earlier with NU’s consent), he will be eligible to receive a special benefit, subject to reduction for termination prior to age 65, consisting of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service. Alternatively, if Mr. Olivier voluntarily terminates his employment with NU after his 60th birthday, or NU terminates his employment earlier for any reason other than "cause" (as defined in his employment agreement, generally meaning willful and continued failure to perform his duties after written notice, a violation of NU’s Standards of Business Conduct or conviction of a felony) he is eligible to receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the Supplemental Plan and the benefit described in the preceding sentence. These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan. If the conditions described above are not met, then Mr. Olivier would be eligible for the make whole benefit under the Supplemental Plan. Amounts reported in the table assume the termination of his employment at age 60 and payment of the lump sum benefit of $2,050,000, offset by Retirement Plan benefits.

(3)

Mrs. Grisé retired from NU effective July 1, 2007 with a vested benefit of $4,754 per month in the Retirement Plan.

NONQUALIFIED DEFERRED COMPENSATION IN 2007


Name	Executive Contributions in Last FY ($)(1)	Registrant Contributions in Last FY ($)(2)	Aggregate Earnings in Last FY ($)	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at Last FYE ($)(3)
Charles W. Shivery	29,619	1,358,004	74,652	--	2,376,430
David R. McHale	--	118,675	4,903	--	201,311
Leon J. Olivier	124,766	148,298	91,760	--	1,196,301
Raymond P. Necci	44,377	72,297	8,513	--	247,489
Gregory B. Butler	3,822	173,276	9,666	--	366,170
Cheryl W. Grisé	5,774	277,699	34,025	--	878,573

(1)

Reflects base salary deferrals by the Named Executive Officers under the Deferral Plan for 2007. Named Executive Officers who participate in the Deferral Plan are provided with a variety of investment opportunities, which the individual can modify and reallocate at any time. Fund gains and losses are updated daily by our recordkeeper, Fidelity Investments. Contributions by the Named Executive Officer are vested at all times; however, the employer matching contribution vests after three years and will be forfeited if the executive’s employment terminates, other than for retirement, prior to vesting.

(2)

Includes employer matching contributions made to the Deferral Plan as of December 31, 2007 and posted on January 31, 2008, as reported in the All Other Compensation column of the Summary Compensation Table (Mr. Shivery: $22,869; Mr. Olivier: $7,113; Mr. Necci: $2,125, Mr. Butler: $4,717; and Mrs. Grisé: $1,911). The employer matching contribution is deemed to be invested in common shares but is paid in cash at the time of distribution. All other amounts relate to the value of common shares, the distribution of which was automatically deferred upon vesting of underlying RSUs pursuant to the terms of the respective Long-Term Incentive Programs, calculated using the closing price of the common shares on either the vesting date (February 25, 2007) or the last trading day prior to the vesting date if the vesting date falls on a weekend or holiday. For more information, see the footnotes to the Options Exercised and Stock Vested Table.

(3)

Includes the total market value of Deferral Plan balances at December 31, 2007 plus the value of vested RSUs for which the distribution of common shares is currently deferred, based on $31.31 per share, the closing price of our common shares on December 31, 2007.

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

In the event of a change of control, Messrs. Shivery, McHale, Olivier and Butler are each entitled to receive compensation and benefits following termination of employment without "cause" or upon termination of employment by the executive for "good reason." The Compensation Committee believes that termination for "good reason" is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Termination for "cause" generally means due to a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to company property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement. Termination for "good reason" generally is deemed to occur following an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement, or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control.

Generally, a "change of control" means a change in ownership or control effected through (i) the acquisition of 20% or more of the combined voting power of common shares or other voting securities of NU, (ii) a change in the majority of the Board of Trustees of NU over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding NU common shares immediately prior to such business combination do not beneficially own more than 50% of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than to an entity with respect to which following completion of the transaction more than 50% (75% for Messrs. Olivier and Necci) of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.

The discussion and tables below reflect the amount of compensation that would be payable to each of the Named Executive Officers, except for Mrs. Grisé, in the event of: (i) termination of employment for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination (or voluntary termination for good reason); (iv) termination in the event of disability; (v) death; and (vi) termination following a change of control. The amounts shown assume that each termination was effective as of December 31, 2007, the last business day of the fiscal year as required under SEC reporting requirements.

Payments Upon Termination

Regardless of the manner in which the employment of a Named Executive Officer terminates, he is entitled to receive certain amounts earned during his term of employment. Such amounts include:

Vested restricted shares and RSUs;

Amounts contributed under the Deferral Plan;

Vested matching contributions under the Deferral Plan;

Pay for unused vacation; and

Amounts accrued and vested through the Retirement Plan, the 401k Plan and the Supplemental Plan.

Post-Employment Compensation: Termination for Cause


Type of Payment	Shivery ($)	McHale ($)	Olivier ($)	Necci ($)	Butler ($)

Incentive Programs (1)
Annual Incentives	--	--	--	--	--
Performance Cash	--	--	--	--	--
Restricted Stock and RSUs	2,106,185	201,311	254,850	134,178	349,458
Pension and Deferred Compensation
Qualified Retirement Plan (2)	155,498	262,348	189,224	1,150,052	133,144
Supplemental Plan Payments (2)	--	--	--	--	--
Special Retirement Benefit (2)	--	--	--	--	--
Deferral Plan (3)	175,727	--	917,443	111,026	11,296
Other Benefits
Health and Welfare Cash Value	--	--	--	--	--
Perquisites	--	--	--	--	--
Separation Payments
Excise Tax & Gross-Up	--	--	--	--	--
Separation Payment for Non-Compete Agreement	--	--	--	--	--
Separation Payment for Liquidated Damages	--	--	--	--	--
Total	$2,437,410	$463,659	$1,361,517	$1,395,256	$493,898

(1)

The assumed termination date for purposes of this table is December 31, 2007. Only those RSUs that were previously vested but for which common shares were not distributed would be payable upon termination of employment for cause.

(2)

Only vested benefits under the Retirement Plan would be available to Named Executive Officers in the event of termination of employment for cause. With the exception of Mr. Shivery and Mr. Necci, all of our Named Executive Officers are vested and eligible to receive a reduced benefit beginning at age 55 under the Retirement Plan. Mr. Necci became eligible to receive an unreduced benefit beginning at age 55. With the exception of Mr. Necci, none of the other Named Executive Officers has satisfied the minimum requirements for the make-whole benefit.

(3)

The amounts in this row represent vested balances in the Deferral Plan at December 31, 2007, which would be payable in accordance with previous distribution elections following termination of employment for any reason.

II.

Post-Employment Compensation: Voluntary Termination


Type of Payment	Shivery ($)	McHale ($)	Olivier ($)	Necci ($)	Butler ($)

Incentive Programs (1)
Annual Incentives	1,683,360	487,620	452,226	208,660	390,700
Performance Cash	2,706,420	268,190	590,915	258,580	341,250
Restricted Stock and RSUs	4,270,458	201,311	659,895	308,627	349,458
Pension and Deferred Compensation
Qualified Retirement Plan (2)	181,315	262,348	189,224	1,150,052	133,144
Supplemental Plan Payments (2)	3,252,426	--	--	1,354,069	--
Special Retirement Benefit (2)	1,845,270	--	1,241,765	--	--
Deferral Plan (3)	270,245	--	941,451	113,311	11,296
Other Benefits
Health and Welfare Cash Value (4)	99,704	--	--	--	--
Perquisites	--	--	--	--	--
Separation Payments
Excise Tax & Gross-Up	--	--	--	--	--
Separation Payment for Non-Compete Agreement	--	--	--	--	--
Separation Payment for Liquidated Damages	--	--	--	--	--
Total	$14,309,198	$1,219,469	$4,075,476	$3,393,299	$1,225,848

(1)

All Named Executive Officers would receive a payout under the 2007 Annual Incentive Program and the 2005-2007 Performance Cash Program based on actual results. All current Performance Cash Programs provide for pro-rated payout in the event that a participant's employment terminates for retirement, death, or disability prior to the end of the performance period. "Retirement" is defined as eligibility to immediately commence a post-employment benefit under the Retirement Plan, Supplemental Plan or other employment agreement with NU or one of its subsidiaries. Messrs. Shivery, Olivier and Necci satisfy this definition and would, therefore, be entitled to receive prorated payouts under the 2006 – 2008 and 2007 – 2009 Performance Cash Programs, which payments would be based on year-end results and paid in the first quarters of 2008 and 2009, respectively. The amounts reflected in the table are projections assuming target performance under the Performance Cash Programs. For RSUs granted under the Long-Term Incentive Programs that commenced in 2004, 2005, 2006 and 2007, Messrs. Shivery, Olivier and Necci would be entitled to receive a prorated payout of unvested RSUs for time worked in the vesting period that would otherwise be completed on February 25, 2008. All Named Executive Officers would receive full payment for all previously vested RSUs for which common shares had not yet been distributed.

(2)

Pension amounts are present values at the end of 2007 of life annuities payable to each Named Executive Officer at age 65 (age 60 for Mr. Olivier, and age 55 for Mr. Necci). All assumptions used to calculate these pension values are the same as those described in the notes attached to the Pension Benefits Table.

(3)

The deferred compensation values are vested balances for all Named Executive Officers. Messrs. Shivery, Olivier, and Necci are eligible for accelerated vesting of employer matches for 2004 through 2006 because of their retirement eligibility. Mr. Butler would forfeit these unvested matches upon voluntary termination of employment. Mr. McHale does not participate in the Deferral Plan.

(4)

Mr. Shivery's employment agreement provides for immediate eligibility to receive retiree health benefits upon retirement which would be provided in cash in lieu of such benefits.

III.

Post-Employment Compensation: Involuntary Termination, Not for Cause


Type of Payment	Shivery ($)	McHale ($)	Olivier ($)	Necci ($)	Butler ($)

Incentive Programs (1)
Annual Incentives	1,683,360	487,620	452,226	208,660	390,700
Performance Cash	2,706,420	268,190	590,915	258,580	341,250
Restricted Stock and RSUs	7,772,891	201,311	659,895	308,627	349,458
Pension and Deferred Compensation
Qualified Retirement Plan (2)	176,678	299,813	271,922	1,150,052	151,451
Supplemental Plan Payments (2)	3,141,932	--	--	1,354,069	--
Special Retirement Benefit (2)	2,972,333	1,100,305	1,778,078	--	930,265
Deferral Plan (3)	270,245	--	941,451	113,311	11,296
Other Benefits
Health and Welfare Cash Value (4)	81,248	10,044	72,175	1,611	93,649
Perquisites	7,000	7,000	7,000	--	7,000
Separation Payments
Excise Tax & Gross-Up	--	--	--	--	--
Separation Payment for Non-Compete Agreement (5)	1,974,616	716,323	--	--	630,703
Separation Payment for Liquidated Damages (5)	1,974,616	716,323	--	--	630,703
Total	$22,761,339	$3,806,929	$4,773,662	$3,394,910	$3,536,475

(1)

Messrs. Shivery, Olivier and Necci would satisfy the criteria for retirement treatment under the Long-Term Incentive Program as described in the Voluntary Termination Table. Mr. Shivery's employment agreement provides for full vesting and distribution of all restricted shares and common shares in respect of RSUs upon involuntary termination of employment without cause. NU would distribute to all Named Executive Officers common shares in respect of all previously vested RSUs for which common shares had not been distributed.

(2)

Employment agreements with Messrs. Shivery, McHale and Butler provide for the addition of two years of age and service in the calculation of pension benefits available upon an involuntary termination without cause. For Mr. Shivery, the two additional years of age and service is in addition to the three additional years of service to which he is entitled upon voluntary termination of employment. Pension amounts reflected above are the present values at the end of 2007 of benefits payable to each Named Executive Officer at the earliest unreduced benefit age (Mr. Shivery: age 63; Mr. McHale: age 63; Mr. Olivier: age 58; Mr. Necci: age 55 and Mr. Butler: age 62). Except for the benefit payable to Mr. Olivier, these benefits are annuities calculated using the same assumptions described in the notes to the Pension Benefits Table. Under the terms of his employment agreement, if Mr. Olivier’s employment is terminated for any reason other than for "cause" (as defined in his employment agreement, generally meaning willful and continued failure to perform his duties after written notice, a violation of NU’s Standards of Business Conduct or conviction of a felony), he will be immediately eligible to receive a special retirement benefit of $2,050,000 paid as a lump sum, offset by benefits from the Retirement Plan.

(3)

The deferred compensation values are vested balances for all Named Executive Officers. Messrs. Shivery, Olivier, Necci and Butler are eligible for accelerated vesting of the employer matches for 2004 through 2006 because of their retirement eligibility.

(4)

Employment agreements with Messrs. Shivery, McHale and Butler provide for the payment of two years of active benefits value and retirement benefits if adding the "two additional years" of age and service would have made the officer eligible under the retiree health plan. Mr. Shivery’s employment agreement provides for automatic eligibility for retiree health benefits, and Mr. Olivier’s employment agreement provides for retiree health benefits if his employment terminates involuntarily without cause. Six months of employer-paid COBRA benefits are generally made available to all employees whose employment terminates involuntarily without cause. Thus, the amounts reported in the table are the cash value of 18 months of employer contributions toward active employee benefits for all Named Executive Officers, plus retiree benefits for Messrs. Shivery, Olivier and Butler after 24 months, each of whom would not otherwise be eligible for retiree health benefits except as provided under their employment agreements. These amounts would be paid as a lump sum and grossed up for applicable withholding taxes. With the exception of Mr. Necci, all of the NEOs are also eligible to receive reimbursement for two years of financial planning and tax preparation services.

(5)

Employment agreements with Messrs. Shivery, McHale and Butler provide for a severance payment equal to two times the base salary plus annual incentives at target, one multiple of which is conditioned upon the execution of a non-competition agreement.

IV.

Post-Employment Compensation: Termination Upon Disability


Type of Payment	Shivery ($)	McHale ($)	Olivier ($)	Necci ($)	Butler ($)

Incentive Programs (1)
Annual Incentives	1,683,360	487,620	452,226	208,660	390,700
Performance Cash	2,706,420	518,517	590,915	258,580	613,498
Restricted Stock and RSUs	4,270,458	201,311	659,895	308,627	349,458
Pension and Deferred Compensation
Qualified Retirement Plan (2)	181,315	592,797	260,225	1,150,052	171,486
Supplemental Plan Payments (2)	3,252,426	2,041,949	--	1,354,069	822,353
Special Retirement Benefit (2)	1,845,270	--	1,428,663	--	--
Deferral Plan (3)	270,245	--	941,451	113,311	11,296
Other Benefits
Health and Welfare Cash Value (4)	92,899	--	82,961	--	--
Perquisites	--	--	--	--	--
Separation Payments
Excise Tax & Gross-Up	--	--	--	--	--
Separation Payment for Non-Compete Agreement	--	--	--	--	--
Separation Payment for Liquidated Damages	--	--	--	--	--
Total	$14,302,393	$3,842,194	$4,416,336	$3,393,299	$2,358,791

(1)

All current long-term Performance Cash Programs provide for a prorated payout in the event that a participant's employment terminates prior to the end of the performance period for reason of disability. While actual values are reported for the 2007 Annual Incentive Program and the 2005 – 2007 Performance Cash Program amounts, amounts shown for the Performance Cash Program for 2006 – 2008, and 2007 – 2009 are based on target performance in accordance with program rules and prorated for time worked in the performance period. For RSUs, a disabled participant would receive payout of unvested RSUs prorated for time worked in the vesting period that would otherwise be completed on February 25, 2008 plus payment for all previously vested but not yet paid RSUs.

(2)

Under our Long-Term Disability (LTD) program, disabled participants in the Retirement Plan are allowed to continue to accrue service in the Retirement Plan during the period when they are receiving disability payments. Disability payments stop when the LTD participant elects to commence pension payments, but not later than age 65. We have assumed similar treatment in the development of the pension amounts reported in this table. For purposes of valuing the pension benefits, we have assumed that each Named Executive Officer would remain on LTD until his first unreduced make whole or target pension benefit age (Mr. Shivery, age 65; Mr. McHale, age 55; Mr. Olivier, age 60; Mr. Necci, age 55; and Mr. Butler, age 62). Except for the benefit payable to Mr. Olivier, all payments would consist of life annuities calculated using the same assumptions detailed in the notes to the Pension Benefits Table. Mr. Olivier's benefit would be paid as a lump sum of $2,050,000, offset by benefits from the Retirement Plan.

(3)

The deferred compensation values are vested balances for all Named Executive Officers because all unvested employer matching contributions would become vested upon disability.

(4)

Mr. Olivier’s employment agreement provides for retiree health benefits if his employment terminates involuntarily without cause, even if he would not otherwise qualify for such benefits. The amount reported is the value of our contributions for these benefits paid as a lump sum grossed up for applicable withholding taxes. Mr. Shivery’s employment agreement provides for immediate eligibility to receive retiree health benefits upon retirement, which would be provided as cash in lieu of such benefits.

Post-Employment Compensation: Death


Type of Payment	Shivery ($)	McHale ($)	Olivier ($)	Necci ($)	Butler ($)

Incentive Programs (1)
Annual Incentives	987,308	282,188	300,362	147,923	248,459
Performance Cash	2,706,420	518,517	590,915	258,580	613,498
Restricted Stock and RSUs	4,270,458	201,311	659,895	308,627	349,458
Pension and Deferred Compensation
Qualified Retirement Plan (2)	169,809	1,031,233	271,922	1,082,912	120,786
Supplemental Plan Payments (2)	3,045,348	3,523,147	--	1,275,018	263,443
Special Retirement Benefit (2)	1,727,805	--	1,778,078	--	--
Deferral Plan (3)	270,245	--	941,451	113,311	11,296
Other Benefits
Health and Welfare Cash Value (4)	55,599	--	38,443	--	--
Perquisites	--	--	--	--	--
Separation Payments
Excise Tax & Gross-Up	--	--	--	--	--
Separation Payment for Non-Compete Agreement	--	--	--	--	--
Separation Payment for Liquidated Damages	--	--	--	--	--
Total	$13,232,992	$5,556,396	$4,581,066	$3,186,371	$1,606,940

(1)

The 2006-2008 and 2007-2009 Performance Cash Programs provide for a prorated payout in the event that a participant's employment terminates prior to the end of the performance period for reason of death. All such payments would be prorated for time worked in each performance period and paid at target. For RSUs, a deceased participant's beneficiary would receive a prorated payout of unvested RSUs for time worked in the vesting period that would otherwise be completed on February 25, 2008 plus payment for all previously vested but not yet paid RSUs.

(2)

Represents the lump sum present value of pension payments to the surviving beneficiary of each Named Executive Officer.

(3)

The deferred compensation values are vested balances for all Named Executive Officers since all unvested employer matching contributions would become vested on account of death.

(4)

Upon his death, Mr. Olivier’s employment agreement provides for retiree health benefits for his spouse if she would not otherwise qualify for such benefits. The amount reported is the value of our contributions for these benefits paid as a lump sum grossed up for applicable withholding taxes.

Payments Made Upon a Change of Control:

The employment agreements with Messrs. Shivery, McHale, Olivier and Butler include change of control benefits. NU has not entered into an employment agreement with Mr. Necci. Messrs. Olivier and Necci participate in the Special Severance Program for Officers of Northeast Utilities System Companies (SSP) which provides benefits upon termination of employment in connection with a change of control. The employment agreements and the SSP are binding on NU and, except for Mr. Shivery’s agreement, on certain of NU’s majority-owned subsidiaries, including us. The terms of the various employment agreements are substantially similar, except for the agreement with Mr. Olivier, which refers instead to the change of control provisions of the SSP.

Pursuant to the employment agreements and under the terms of the SSP, if an executive officer’s employment terminates following a change of control, other than termination of employment for "cause" (as defined in the employment agreements, generally meaning wilful and continued failure to perform his duties after written notice, a violation of NU’s Standards of Business Conduct or conviction of a felony), or by reason of death or disability), or if the executive officer terminates his employment for "good reason" (as defined in the employment agreements, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his or her principal place of business immediately prior to a change of control), then the executive officer will receive the benefits listed below, which receipt is conditioned upon delivery of a binding release of all legal claims against NU and its subsidiaries:

A lump sum severance payment (except for Messrs. Olivier and Necci) of two-times the sum of the executive’s base salary plus all annual awards that would be payable for the relevant year determined at target (Base Compensation);

As consideration for a non-competition and non-solicitation covenant, a lump sum payment in an amount equal to the Base Compensation (equal to two-times Base Compensation for Messrs. Olivier and Necci under the terms of the SSP);

Health continuation coverage, or the cash equivalent, paid by us for three years (two years for Mr. Olivier). Mr. Necci is eligible to retire and would therefore be eligible for retiree benefits;

Benefits as if provided under the Supplemental Plan, notwithstanding eligibility requirements for the Target Benefit, including favorable actuarial reductions and the addition of three years to the executive’s age and years of service as compared to benefits available upon voluntary termination of employment (except for Mr. Olivier, whose benefits are described below, and Mr. Necci);

Automatic vesting and distribution of common shares in respect of all unvested RSUs; and

A lump sum payment in an amount equal to the excise tax charged to the executive under the Internal Revenue Code as a result of the receipt of any change of control payments, plus tax gross-up (except for Messrs. Olivier and Necci).

The summaries of the employment agreements above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the employment agreements, copies of which have been filed as exhibits to our Annual Report on Form 10-K for the year ended December 31, 2007.

VI.

Post-Employment Compensation: Termination Following a Change of Control


Type of Payment	Shivery ($)	McHale ($)	Olivier ($)	Necci ($)	Butler ($)

Incentive Programs (1)
Annual Incentives	1,683,360	487,620	452,226	208,660	390,700
Performance Cash	4,125,000	811,990	871,900	382,090	894,550
Restricted Stock and RSUs	7,772,891	1,191,369	1,218,209	513,682	1,300,291
Pension and Deferred Compensation
Qualified Retirement Plan (2)	181,315	319,037	271,922	1,150,052	161,197
Supplemental Plan Payments (2)	3,252,426	--	--	1,354,069	--
Special Retirement Benefit (2)	3,690,540	1,200,788	1,778,078	--	1,103,689
Deferral Plan (3)	270,245	--	941,451	113,311	11,296
Other Benefits
Health and Welfare Cash Value (4)	85,527	123,431	72,175	1,611	110,717
Perquisites	8,500	8,500	8,500	--	8,500
Separation Payments
Excise Tax & Gross-Up (5)	5,020,003	2,029,702	--	--	1,752,663
Separation Payment for Non-Compete Agreement	1,974,616	716,323	762,458	443,769	630,703
Separation Payment for Liquidated Damages	3,949,232	1,432,646	762,458	443,769	1,261,405
Total	$32,013,655	$8,321,406	$7,139,377	$4,611,013	$7,625,711

(1)

All Named Executive Officers would receive a payout under the 2007 Annual Incentive Program and the 2005 – 2007 Performance Cash Program based on actual results. Under the terms of the 2006 – 2008 and 2007 – 2009 Performance Cash Programs, participants who are terminated upon a Change of Control become eligible for immediate payout of a target award, and under the terms of the outstanding grants of restricted shares and RSUs, all unvested shares and share units held by participants terminated upon a Change of Control would be immediately vested and paid.

(2)

Employment agreements with Messrs. Shivery, McHale and Butler provide for the addition of three years of age and service in the calculation of pension benefits available upon termination following a Change of Control. For Mr. Shivery, these three years of added age and service are in addition to the three years of added service provided upon his voluntary termination. Pension amounts reflected in the table are present values at the end of 2007 of benefits payable to each Named Executive Officer at the earliest unreduced benefit age (Mr. Shivery: age 62; Mr. McHale: age 62; Mr. Olivier: age 58; Mr. Necci: age 55; and Mr. Butler: age 62). All but the benefit payable to Mr. Olivier are annuities that are calculated using the assumptions detailed in the notes to the Pension Benefits Table. Mr. Olivier's benefit would be paid as a lump sum of $2,050,000 as offset by benefits from the Retirement Plan.

(3)

The deferred compensation values are vested balances for all Named Executive Officers since all unvested matching contribution would become fully vested upon the occurrence of a change of control.

(4)

Employment agreements with Messrs. Shivery, McHale and Butler provide for the payment of three years of active health benefits value and retiree health benefits if adding the three years of age and service would have made the executive eligible under the Retirement Plan. Messrs. Olivier and Necci participate in the SSP and are eligible for two years of active health benefits continuation. Six months of company-paid COBRA benefits are generally made available to all employees whose employment terminates involuntarily without cause. As a result, the amounts reported in the table represent the cash value of 30 months of employer contributions for each Named Executive Officer except Mr. Olivier, whose benefits would consist of the cash value of 18 months of employer contributions. Mr. Necci is eligible to retire and would therefore receive retiree benefits. In addition to continuation of active health benefits, retiree health benefits for Messrs. Shivery and Olivier, which are provided for in each of their respective employment agreements regardless of eligibility, would be paid as a lump sum and grossed up for applicable withholding taxes. With the exception of Mr. Necci, all Named Executive Officers are also eligible to receive reimbursement of fees for financial planning and tax preparation services for three years.

(5)

Excise Tax gross-up: Upon a Change of Control, employees may be subject to certain excise taxes under Section 280G of the Internal Revenue Code. Employment agreements with each Named Executive Officer except Messrs. Olivier and Necci provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on a Section 280G excise tax rate of 20%, a statutory federal income tax withholding rate of 35%, a Connecticut state income tax rate of 5%, and a Medicare tax rate of 1.45%. Mr. Olivier's and Mr. Necci’s benefits through the SSP do not provide for this payment. Severance Payments: Employment agreements with each NEO except Messrs. Olivier and Necci provide for a severance payment equal to three-times

base salary plus annual incentives at target, one multiple of which is associated with the execution of a written non-competition agreement. Mr. Olivier's and Mr. Necci’s benefits under the SSP would consist of a payment of two-times base salary plus target annual incentives, all of which is conditioned upon the execution of a written non-competition agreement.

Cheryl W. Grisé

The following table sets forth the payments to be received by Cheryl Grisé, former chief executive officer of CL&P and former executive vice president of NU, following her retirement from NU on July 1, 2007. At the time Mrs. Grisé announced her intention to retire, NU entered into an agreement in principle with her to ensure that she would remain with NU until at least July 1, 2007. Under the agreement in principle, on January 2, 2008, NU paid Mrs. Grisé a lump sum cash payment of $120,535 (i) as consideration for a standard general release of all claims against NU in connection with her employment, which she delivered to NU upon her retirement, and (ii) in lieu of a grant of RSUs and/or performance cash under the 2007-2009 long-term incentive program. Because Mrs. Grisé retired, she is also entitled to receive a payment under the 2007 Annual Incentive Program. In addition, as set forth in the notes to the Grants of Plan-Based Awards Table, Mrs. Grisé is eligible for distributions in the first quarter of 2008 under the 2005-2007 Performance Cash Program based on goal achievement, prorated to reflect that Mrs. Grisé performed services for two and one-half years out of the three-year period, and an award under the 2006-2008 Performance Cash Program based on goal achievement, prorated to reflect that Mrs. Grisé performed services for one and one-half years out of the three-year period ending December 31, 2008. Mrs. Grisé’s unvested RSUs from grants made in 2004, 2005, and 2006 were prorated based on service during 2007, and the remainder were forfeited. Mrs. Grisé is entitled to all of her vested but deferred RSUs, and she is eligible for a vested benefit under the Retirement Plan and the SERP.

Post-Employment Compensation: Cheryl W. Grisé


Payment	($)
Incentive Programs (1)
Annual Incentive	187,645
Performance Cash Program	711,994
Restricted Stock and RSUs	778,742
Pension and Deferred Compensation (2)
Qualified Retirement Plan	28,525
Supplemental Plan Payments	--
Special Retirement Benefits	--
Other Benefits (3)
Health and Welfare Cash Value	--
Separation Payments (4)
Separation Payment for Non-Compete Agreement	120,535
Separation Payment for Liquidated Damages	--
Total	1,827,441

[nu2007form10kedgar003.gif]

(1)

Upon retirement, Mrs. Grisé became eligible to receive a payout under the 2007 Annual Incentive Program. She is also eligible to receive prorated payouts under the 2005-2007 and 2006-2008 Performance Cash Programs, which will be paid in 2008 and 2009, respectively, based on final performance. Amounts reflected in the table are actual payouts for the 2005-2007 Performance Cash Program and estimated payouts based on target performance for the 2006-2008 Performance Cash Program. Upon Mrs. Grisé’s retirement on July 1, 2007, unvested RSUs were vested in proportion to the time she was employed with NU in 2007. Under the terms of the long-term incentive programs in which Mrs. Grisé participated, the remaining unvested RSUs were forfeited. A total of 24,872 RSUs vested and 19,373 RSUs were forfeited. On January 4, 2008, NU distributed to Mrs. Grisé 17,361 common shares in respect of all previously vested RSUs (for which distribution of common shares had been deferred) following a six-month delay required for deferred compensation paid to "key employees" under Section 409A of the Internal Revenue Code, and NU withheld 7,511 shares to satisfy Mrs. Grisé's tax obligations. Mrs. Grisé realized $778,743 in ordinary income as a result of this transaction.

(2)

Pension values are the total accrued pension benefit payable as an annuity that pays 75% to her surviving spouse. At the time of her retirement, Mrs. Grisé began receiving her qualified retirement benefit. In compliance with Section 409A of the Internal Revenue Code, NU delayed the start of Mrs. Grisé's SERP payments until six months after her retirement. On January 2, 2008, NU paid six-months of Mrs. Grisé's SERP "make-whole" benefit ($134,046) and six months of the SERP "target" benefit ($155,155). Mrs. Grisé's monthly SERP "make-whole" and "target" benefits are $21,693 and $25,109, respectively. Assumptions used in the calculation of this benefit are further discussed in the notes to the Pension Benefits table.

(3)

Under the Retirement Plan, Mrs. Grisé became eligible to receive health benefits upon retirement. Mrs. Grisé did not receive any health and welfare benefits in excess of the benefits NU offers to all of its employees.

(4)

In lieu of participation in the 2007-2009 Long-Term Incentive Program, Mrs. Grisé’s agreement in principle provides for a lump sum payment in the amount of $120,535, which NU paid to her six months after her retirement on January 2, 2008.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, expected to be dated March 31, 2008, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

Certain information required by this Item 12 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

CL&P

NU owns 100% of the outstanding common stock of CL&P. The following table sets forth, as of February 28, 2008, the beneficial ownership of the equity securities of NU by (i) the Chief Executive Officer of CL&P and the directors and executive officers of CL&P listed on the Summary Compensation Table in Item 11 and (ii) all of the current executive officers and directors of CL&P, as a group. No equity securities of CL&P are owned by any of the directors and executive officers of CL&P.


	Amount and Nature of Beneficial Ownership ⁽¹⁾
Name	Shares		Options⁽²⁾	Total	Percent of Class	Restricted Share Units ⁽³⁾
Leon J. Olivier, CEO, Director	18,205	⁽⁵⁾	0	18,205	*	45,199
David R. McHale, CFO, Director	13,092	^(5)(6)(7)	0	13,092	*	42,107
Gregory B. Butler, Senior Vice President and General Counsel	27,633	^(4)(5)(6)	0	27,633	*	43,172
Raymond P. Necci, President, COO, Director	19,151	^(5)(6)(7)	0	19,151	*	17,251
Charles W. Shivery, Director	47,068	⁽⁵⁾⁽⁸⁾	29,024	76,092	*	312,442
Cheryl W. Grisé, former chief executive officer – CL&P	74,330	^(5)(7)(9)	0	74,330	*	1,901
All directors and Executive Officers as a Group (8 persons)	215,822		37,424	253,246	*	479,451

Less than 1% of common shares outstanding.

(1)

The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as noted below.

(2)

Reflects common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 28, 2008.

(3)

Includes unissued common shares consisting of restricted share units and deferred restricted share units as to which none of the Directors or Named Executive Officers has voting or investment power. Also includes "phantom" common shares representing employer matching contributions, distributable only in cash held by individuals who participate in the NU Deferred Compensation Plan for Executives. Accordingly, these securities have been excluded from the "Total" column.

(4)

Includes 24,850 shares owned jointly by Mr. Butler and his wife with whom he shares voting and investment power.

(5)

Includes common shares held in a 401k Plan for the Employee Stock Ownership Plan Account over which the holder has sole voting and no investment power (Mr. Butler: 2,388 shares; Mr. McHale: 3,014 shares; Mr. Necci: 3,125 shares; Mr. Olivier: 1,150 shares; Mrs. Grisé: 3,967 shares; and Mr. Shivery: 1,304 shares).

(6)

Includes common shares held in a 401k Plan NU Common Shares Fund over which the holder has sole voting and no investment power (Mr. Butler: 395 shares, Mr. McHale: 1,445 shares and Mr. Necci: 228 shares).

(7)

Includes common shares held in a 401k Plan TRAESOP/PAYSOP account over which the holder has sole voting and no investment power (Mr. McHale: 100 shares, Mr. Necci: 1,913 shares and Mrs. Grisé: 778 shares).

(8)

Includes 1,500 shares owned jointly by Mr. Shivery and his wife with whom he shares voting and investment power.

(9)

Includes 265 shares held by Mrs. Grisé’s husband as custodian for their children. Mrs. Grisé and her husband share voting and investment power with respect to these 265 shares. Mrs. Grisé resigned as Chief Executive Officer of CL&P on January 15, 2007 and retired from NU on July 1, 2007.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth the number of our common shares issuable under our equity compensation plans, as well as their weighted exercise price, in accordance with the rules of the SEC:



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	1,160,360^(a)	18.34^(b)	4,096,447^(c)
Equity compensation plans not approved by security holders	0^(d)	0	0
Total	1,160,360	18.34	4,096,447

^(a)

Includes 397,180 common shares to be issued upon exercise of options, and 763,180 common shares for distribution of restricted share units pursuant to the terms of our Incentive Plan.

^(b)

The weighted-average exercise price in Column (b) does not take into account restricted share units, which have no exercise price.

^(c)

Includes 1,041,364 common shares issuable under our Employee Share Purchase Plan II.

^(d)

All of our current compensation plans under which equity securities of NU are authorized for issuance have been approved by our shareholders.

Item 13. Certain Relationships and Related Transactions, and Trustee Independence

Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, expected to be dated March 31, 2008, which will be filed with the Securities and Exchange Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

The Directors of CL&P are employees of CL&P and/or other subsidiaries of NU and thus are not considered independent under the NYSE guidelines discussed under "Trustee Independence" in the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 31, 2008, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

Certain information required by this Item 13 has been omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

Item 14. Principal Accountant Fees and Services

Incorporated herein by reference is the information contained in the section "Relationship with Independent Auditors" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 31, 2008, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, WMECO

None of CL&P, PSNH and WMECO is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU's Board of Trustees. The NU Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair and/or Vice Chair provided that such offices are held by Trustees of NU who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the NU Audit Committee at the next regularly scheduled meeting of the NU Audit Committee.

The following relates to fees and services for the entire NU system, including CL&P, PSNH, and WMECO:

Fees Paid to Principal Auditor

We paid Deloitte & Touche LLP fees aggregating $3,108,754 and $3,134,359 for the years ended December 31, 2007 and 2006, respectively, comprised of the following:

Audit Fees

The aggregate fees billed to us and our subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the Deloitte Entities), for audit services rendered for the years ended December 31, 2007 and 2006 totaled $2,789,900 and $2,938,255, respectively. The audit fees were incurred for audits of our annual consolidated financial statements and those of our subsidiaries, reviews of financial statements included in our Quarterly Reports on Form 10-Q and those of our subsidiaries, comfort letters, consents and other costs related to registration statements and financings. The fees also included audits of internal controls over financial reporting as of December 31, 2007 and 2006.

Audit Related Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2007 and 2006 totaled $260,000 and $150,000, respectively, primarily related to the examination of management’s assertions about the securitization subsidiaries of CL&P, PSNH and WMECO and about our 401k Plan.

Tax Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2007 and 2006 totaled $57,354 and $44,604, respectively. These services related solely to reviews of tax returns. There were no services related to tax advice or tax planning.

All Other Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for services other than the services described above totaled $1,500 for each of the years ended December 31, 2007 and 2006 consisting of a license fee for access to an accounting research database.

The NU Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for us by our independent auditors, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the NU Audit Committee prior to the completion of the audit. The NU Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full NU Audit Committee at its next scheduled meeting. During 2007, the only services provided by the Deloitte Entities that were not pre-approved by the Audit Committee were de minimis services related to the issuance of an agreed-upon procedures report in connection with a debt financing transaction by PSNH for which the Deloitte Entities received a fee of $5,000. The Audit Committee approved these de minimis services prior to the completion of the audit. The Deloitte Entities did not provide any other services that were not pre-approved by the Audit Committee.

The NU Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of us in all respects.

Part IV

Item 15.

Exhibits and Financial Statement Schedules

(a)

Financial Statements:

The Reports of the Independent Registered Public Accounting Firm and financial statements of CL&P, PSNH and WMECO are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data").

Report of Independent Registered Public Accounting Firm

S-1

Schedules:

Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P

and Subsidiaries, PSNH and Subsidiaries, and WMECO and Subsidiary

are listed in the Index to Financial Statement Schedules

S-2

Exhibit Index

E-1

NORTHEAST UTILITIES

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHEAST UTILITIES

(Registrant)


By	/s/ Charles W. Shivery	Date
	Charles W. Shivery
	Chairman of the Board,	February 28, 2008
	President and Chief Executive Officer
	(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Charles W. Shivery	Chairman of the Board, President and Chief Executive Officer, and a Trustee	February 28, 2008
Charles W. Shivery
	(Principal Executive Officer)


/s/ David R. McHale	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 28, 2008
David R. McHale


/s/ Shirley M. Payne	Vice President - Accounting and Controller	February 28, 2008
Shirley M. Payne

/s/ Richard H. Booth	Trustee	February 28, 2008
Richard H. Booth

/s/ Cotton M. Cleveland	Trustee	February 28, 2008
Cotton M. Cleveland

/s/ Sanford Cloud, Jr.	Trustee	February 28, 2008
Sanford Cloud, Jr.

/s/ James F. Cordes	Trustee	February 28, 2008
James F. Cordes

/s/ E. Gail de Planque	Trustee	February 28, 2008
E. Gail de Planque

/s/ John G. Graham	Trustee	February 28, 2008
John G. Graham

/s/ Elizabeth T. Kennan	Trustee	February 28, 2008
Elizabeth T. Kennan


/s/ Kenneth R. Leibler	Trustee	February 28, 2008
Kenneth R. Leibler

/s/ Robert E. Patricelli	Trustee	February 28, 2008
Robert E. Patricelli

/s/ John F. Swope	Trustee	February 28, 2008
John F. Swope

THE CONNECTICUT LIGHT AND POWER COMPANY

SIGNATURES

THE CONNECTICUT LIGHT AND POWER COMPANY

(Registrant)


By	/s/ Leon J. Olivier	Date
	Leon J. Olivier
	Chief Executive Officer	February 28, 2008
	(Principal Executive Officer)


Signature	Title	Date

/s/ Charles W. Shivery	Chairman and a Director	February 28, 2008
Charles W. Shivery


/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 28, 2008
Leon J. Olivier	(Principal Executive Officer)


/s/ Raymond P. Necci	President and Chief Operating Officer	February 28, 2008
Raymond P. Necci	and a Director


/s/ David R. McHale	Senior Vice President and Chief Financial	February 28, 2008
David R. McHale	Officer and a Director
	(Principal Financial Officer)


/s/ Shirley M. Payne	Vice President - Accounting and Controller	February 28, 2008
Shirley M. Payne

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

SIGNATURES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

(Registrant)


By	/s/ Leon J. Olivier	Date
	Leon J. Olivier
	Chief Executive Officer	February 28, 2008
	(Principal Executive Officer)


Signature	Title	Date

/s/ Charles W. Shivery	Chairman and a Director	February 28, 2008
Charles W. Shivery


/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 28, 2008
Leon J. Olivier	(Principal Executive Officer)


/s/ Gary A. Long	President and Chief Operating Officer	February 28, 2008
Gary A. Long	and a Director


/s/ David R. McHale	Senior Vice President and Chief Financial	February 28, 2008
David R. McHale	Officer and a Director
	(Principal Financial Officer)


/s/ Shirley M. Payne	Vice President - Accounting and Controller	February 28, 2008
Shirley M. Payne

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SIGNATURES

WESTERN MASSACHUSETTS ELECTRIC COMPANY

(Registrant)


By	/s/ Leon J. Olivier	Date
	Leon J. Olivier
	Chief Executive Officer	February 28, 2008
	(Principal Executive Officer)


Signature	Title	Date

/s/ Charles W. Shivery	Chairman and a Director	February 28, 2008
Charles W. Shivery


/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 28, 2008
Leon J. Olivier	(Principal Executive Officer)


/s/ Rodney O. Powell	President and Chief Operating Officer	February 28, 2008
Rodney O. Powell	and a Director


/s/ David R. McHale	Senior Vice President and Chief Financial	February 28, 2008
David R. McHale	Officer and a Director
	(Principal Financial Officer)


/s/ Shirley M. Payne	Vice President - Accounting and Controller	February 28, 2008
Shirley M. Payne

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities and the Boards of Directors of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company:

We have audited the consolidated financial statements of Northeast Utilities and subsidiaries (the "Company"), as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and the Company's internal control over financial reporting as of December 31, 2007, and have issued our report thereon dated February 28, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph regarding the adoption of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007); such consolidated financial statements and report are included in Northeast Utilities’ 2007 Annual Report to Shareholders and are incorporated herein by reference.

We have also audited the consolidated financial statements of The Connecticut Light and Power Company ("CL&P"), Public Service Company of New Hampshire ("PSNH") and Western Massachusetts Electric Company ("WMECO") as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our reports thereon dated February 28, 2008 (which reports express unqualified opinions and include explanatory paragraphs regarding the adoption of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007); such consolidated financial statements and reports are included in CL&P’s, PSNH’s, and WMECO’s 2007 Annual Reports and are incorporated herein by reference.

Our audits also included the consolidated financial statement schedules of the Company, CL&P, PSNH and WMECO, listed in Item 15. These consolidated financial statement schedules are the responsibility of the managements of the Company, CL&P, PSNH and WMECO. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements for each company taken as a whole, present fairly, in all material respects, the information set forth therein.


/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut
February 28, 2008

S-1

INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule


I.	Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets at December 31, 2007 and 2006	S-3

	Northeast Utilities (Parent) Statements of Income/(Loss) for the Years Ended December 31, 2007, 2006 and 2005	S-4

	Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	S-5

II.	Valuation and Qualifying Accounts and Reserves for 2007, 2006 and 2005:

	Northeast Utilities and Subsidiaries	S-6 - S-8
	The Connecticut Light and Power Company	S-9 - S-11
	Public Service Company of New Hampshire	S-12 - S-14
	Western Massachusetts Electric Company	S-15 - S-17

All other schedules of the companies' for which provision is made in the applicable regulations of the SEC are not required under the related instructions or are not applicable, and therefore have been omitted.

S-2


SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 2007 AND 2006
(Thousands of Dollars)


	2007	2006
ASSETS
Current Assets:
Cash	$ 294	$ 1,791
Notes receivable from affiliated companies	115,600	915,900
Notes and accounts receivable	452	696
Accounts receivable from affiliated companies	4,690	3,540
Taxes receivable	6,971	-
Derivative assets - current	5,133	-
Prepayments	119	122
	133,259	922,049
Deferred Debits and Other Assets:
Investments in subsidiary companies, at equity	3,235,694	2,520,144
Accumulated deferred income taxes	21,058	-
Other	18,153	19,547
	3,274,905	2,539,691
Total Assets	$ 3,408,164	$ 3,461,740

LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$ 42,000	$ -
Long-term debt - current portion	150,000	-
Accounts payable	27	310
Accounts payable to affiliated companies	1,743	14
Accrued taxes	-	240,466
Accrued interest	5,180	5,179
Other	425	870
	199,375	246,839

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	-	1,685
Derivative liabilities - long-term	-	6,483
Other	27,811	2,136
	27,811	10,304
Capitalization:
Long-Term Debt	267,143	406,418
Common shares, $5 par value - authorized
225,000,000 shares; 175,924,694 shares issued
and 155,079,770 shares outstanding in 2007 and
175,420,239 shares issued and 154,233,141 shares
outstanding in 2006	879,623	877,101
Capital surplus, paid in	1,465,946	1,449,586
Deferred contribution plan - employee stock
ownership plan	(26,352)	(34,766)
Retained earnings	946,792	862,660
Accumulated other comprehensive income	9,359	4,498
Treasury stock, 19,705,545 shares in 2007
and 19,684,249 shares in 2006	(361,533)	(360,900)
Common Shareholders' Equity	2,913,835	2,798,179
Total Capitalization	3,180,978	3,204,597
Total Liabilities and Capitalization	$ 3,408,164	$ 3,461,740

S-3


SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME/(LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
(Thousands of Dollars, Except Share Information)




	2007	2006	2005

Operating Revenues	$ -	$ -	$ -

Operating Expenses:
Other	3,786	4,063	7,955
Operating Loss	(3,786)	(4,063)	(7,955)
Interest Expense	27,993	32,945	33,068
Other Income:
Equity in earnings/(losses) of subsidiaries	247,786	473,279	(240,179)
Other, net	30,516	29,493	17,218
Other Income/(Loss), Net	278,302	502,772	(222,961)
Income/(Loss) Before Income Tax Expense/(Benefit)	246,523	465,764	(263,984)
Income Tax Expense/(Benefit)	40	(4,814)	(10,496)
Net Income/(Loss)	$ 246,483	$ 470,578	$ (253,488)

Basic Earnings/(Loss) Per Common Share	$ 1.59	$ 3.06	$ (1.93)

Fully Diluted Earnings/(Loss) Per Common Share	$ 1.59	$ 3.05	$ (1.93)

Basic Common Shares Outstanding (weighted average)	154,759,727	153,767,527	131,638,953
Fully Diluted Common Shares Outstanding (weighted average)	155,304,361	154,146,669	131,638,953

S-4


SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
(Thousands of Dollars)

	2007	2006	2005

Operating Activities:
Net income/(loss)	$ 246,483	$ 470,578	$ (253,488)
Adjustments to reconcile to net cash flows
(used in)/provided by operating activities:
Equity in (earnings)/losses of subsidiaries	(247,786)	(473,279)	240,179
Cash dividends received from subsidiaries	141,891	190,759	142,709
Deferred income taxes	(14,324)	11,582	(13,563)
Other non-cash adjustments	13,006	13,903	9,857
Other sources of cash	1,831	1,064	2,900
Other uses of cash	-	(9,170)	(405)
Changes in current assets and liabilities:
Receivables, net	(906)	4,285	(5,436)
Other current assets	3	14	(20)
Accounts payable	1,446	(448)	(250)
Taxes (receivable)/accrued	(244,675)	228,363	18,394
Other current liabilities	(444)	214	(287)
Net cash flows (used in)/provided by operating activities	(103,475)	437,865	140,590

Investing Activities:
Investment in subsidiaries	(683,427)	(156,577)	(255,650)
Return of investment in subsidiaries	19,869	435,000	-
Decrease/(increase) in NU Money Pool lending	829,800	(563,200)	(142,100)
Other investing activities	1,462	2,185	2,572
Net cash flows provided by/(used in) investing activities	167,704	(282,592)	(395,178)

Financing Activities:
Issuance of common shares	9,056	9,494	450,827
Increase/(decrease) in short-term debt	42,000	(32,000)	(68,000)
Retirements of long-term debt	-	(21,000)	(26,000)
Cash dividends on common shares	(120,988)	(112,745)	(87,554)
Other financing activities	4,206	2,379	(14,539)
Net cash flows (used in)/provided by financing activities	(65,726)	(153,872)	254,734
Net (decrease)/increase in cash	(1,497)	1,401	146
Cash - beginning of year	1,791	390	244
Cash - end of year	$ 294	$ 1,791	$ 390


Supplemental Cash Flow Information:
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$ 25,580	$ 32,498	$ 32,765
Income taxes	$ 259,707	$ (651)	$ 39,101

S-5

Schedule II

Northeast Utilities and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2007

(Thousands of Dollars)


Column A	Column B		Column C						Column D				Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe					Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	22,369	$	29,140	$	(7,106)	(a)	$		18,874	(b)	$		25,529

Reserves not applied against assets:

Operating reserves	$	63,508	$	15,080	$	-		$		13,423	(c)	$		65,165

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries. In November of 2006, the DPUC issued an order allowing CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. At December 31, 2007, CL&P and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $24 million and $8 million, respectively.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith. This amount also includes a reduction to environmental reserves related to Mt. Tom generating plant (Mt. Tom) property that was sold to ECP in 2006.

S-6

Schedule II

Northeast Utilities and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2006

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts (d)	$	25,044	$	29,366	$	1,922	(a)	$		33,963	(b)		$	22,369

Reserves not applied against assets:

Operating reserves	$	68,078	$	27,550	$	-		$		32,121	(c)		$	63,508

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries. In November of 2006, the DPUC issued an order allowing CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. At December 31, 2006, CL&P and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $17 million and $8 million, respectively.

(c)

(d)

Amounts include activity related to accounts that are classified as assets held for sale and discontinued operations.

S-7

Schedule II

Northeast Utilities and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe					Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts (d)	$	25,325	$	27,528	$	975	(a)	$		28,784	(b)			$	25,044

Reserves not applied against assets:

Operating reserves	$	71,766	$	22,359	$	-		$		26,047	(c)			$	68,078

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

(d)

Amounts include activity related to accounts that are classified as assets held for sale and discontinued operations.

S-8

Schedule II

The Connecticut Light and Power Company and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2007

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	1,679	$	18,121	$	(8,243)	(a)	$		3,683	(b)	$	7,874

Reserves not applied against assets:

Operating reserves	$	24,966	$	9,584	$	-		$		7,031	(c)	$	27,519

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries and other adjustments. In November of 2006, the DPUC issued an order allowing CL&P to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. At December 31, 2007, CL&P had uncollectible hardship accounts receivable reserves in the amount of $24 million.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.

S-9

Schedule II

The Connecticut Light and Power Company and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2006

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe					Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	1,982	$	13,582	$	6,470	(a)	$		20,355	(b)		$	1,679

Reserves not applied against assets:

Operating reserves	$	25,155	$	7,181	$	-		$		7,370	(c)		$	24,966

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries and other adjustments. In November of 2006, the DPUC issued an order allowing CL&P to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. At December 31, 2006, CL&P had uncollectible hardship accounts receivable reserves in the amount of $17 million.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.

S-10

Schedule II

The Connecticut Light and Power Company and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)


Column A	Column B		Column C					Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	2,010	$	12,834	$	605	(a)	$	13,467	(b)		$	1,982

Reserves not applied against assets:

Operating reserves	$	27,405	$	8,385	$	-		$	10,635	(c)		$	25,155

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries and other adjustments.

(c)

S-11

Schedule II

Public Service Company of New Hampshire and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2007

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	2,626	$	3,433	$	324	(a)	$		3,708	(b)	$	2,675

Reserves not applied against assets:

Operating reserves	$	10,719	$	1,666	$	-		$		2,481	(c)	$	9,904

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

S-12

Schedule II

Public Service Company of New Hampshire and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2006

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	2,362	$	4,208	$	316	(a)	$		4,260	(b)	$	2,626

Reserves not applied against assets:

Operating reserves	$	10,777	$	1,385	$	-		$		1,443	(c)	$	10,719

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

S-13

Schedule II

Public Service Company of New Hampshire and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	1,764	$	3,904	$	252	(a)	$		3,558	(b)	$	2,362

Reserves not applied against assets:

Operating reserves	$	11,461	$	1,890	$	-		$		2,574	(c)	$	10,777

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

S-14

Schedule II

Western Massachusetts Electric Company and Subsidiary

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2007

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	5,073	$	6,922	$	155	(a)	$		6,451	(b)	$	5,699

Reserves not applied against assets:

Operating reserves	$	2,200	$	1,669	$	-		$		613	(c)	$	3,256

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

S-15

Schedule II

Western Massachusetts Electric Company and Subsidiary

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2006

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	3,653	$	5,503	$	194	(a)	$		4,277	(b)	$	5,073

Reserves not applied against assets:

Operating reserves	$	2,299	$	987	$	-		$		1,086	(c)	$	2,200

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

S-16

Schedule II

Western Massachusetts Electric Company and Subsidiary

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)


Column A	Column B		Column C						Column D			Column E

			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions - describe				Balance at end of period
Reserves deducted from assets to which they apply:

Reserves for uncollectible accounts	$	2,563	$	3,857	$	37	(a)	$		2,804	(b)	$	3,653

Reserves not applied against assets:

Operating reserves	$	2,355	$	836	$	-		$		892	(c)	$	2,299

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

S-17

EXHIBIT INDEX

Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.

Exhibit

Number

Description

Plan of acquisition, reorganization, arrangement, liquidation or succession

(A)

2.1

Amended and Restated Agreement and Plan of Merger (Exhibit 1, NU Form 8-K dated December 2, 1999, File No. 1-5324)

Articles of Incorporation and By-Laws

(A)

Northeast Utilities

3.1

Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 dated June 23, 2005, File No. 70-10315)

(B)

The Connecticut Light and Power Company

3.1

Certificate of Incorporation of CL&P, restated to March 22, 1994 (Exhibit 3.2.1, 1993 CL&P Form 10-K, File No. 0-00404)

3.1.1

Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996 (Exhibit 3.2.2, 1996 CL&P Form 10-K, File No. 0-00404)

3.1.2

Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998 (Exhibit 3.2.3, 1998 CL&P Form 10-K, File No. 0-00404)

3.2

By-laws of CL&P, as amended to January 1, 1997 (Exhibit 3.2.3, 1996 CL&P Form 10-K, File No. 0-00404)

(C)

Public Service Company of New Hampshire

3.1

Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 PSNH Form 10-K, File No. 1-6392)

3.2

By-laws of PSNH, as in effect June 30, 2005 (Exhibit 3.2, PSNH Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-6392)

(D)

Western Massachusetts Electric Company

3.1

Articles of Organization of WMECO, restated to February 23, 1995 (Exhibit 3.4.1, 1994 WMECO Form 10-K, File No. 0-7624)

3.2

By-laws of WMECO, as amended to April 1, 1999 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 1999, File No. 0-7624)

3.2.1

By-laws of WMECO, as further amended to May 1, 2000 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 2000, File No. 0-7624)

Instruments defining the rights of security holders, including indentures

(A)

Northeast Utilities

4.1

Rights Agreement dated as of February 23, 1999, between Northeast Utilities and Northeast Utilities Service Company, as Rights Agent (Exhibit 1, NU Registration Statement on Form 8-A, filed on April 12, 1999, File No. 001-05324)

E-1

4.1.1

Amendment to Rights Agreement (Exhibit 3, NU Form 8-K dated October 13, 1999, File No. 1-5324)

4.1.2

Second Amendment to Rights Agreement (Exhibit B-3, NU 35-CERT, dated February 1, 2002, File No. 070-09463)

4.2

Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee (Exhibit A-3, NU 35-CERT filed April 9, 2002, File No. 70-9535)

4.2.1

First Supplemental Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee, relating to $263M of Senior Notes, Series A, due 2012 (Exhibit A-4, NU 35-CERT filed April 9, 2002, File No. 70-9535)

4.2.2

Second Supplemental Indenture dated as of June 1, 2003, between NU and the Bank of New York as Trustee, relating to $150M of Senior Notes, Series B, due 2008. (Exhibit A-1.3 to NU 35-CERT filed June 6, 2003, File No. 70-10051)

4.3

Amended and Restated Credit Agreement dated December 9, 2005 between NU, the Banks Named Therein, Union Bank of California, N.A. as Administrative Agent, and Barclays Bank, PLC, JPMorgan Chase Bank, N.A. and Union Bank of California, N.A., as Fronting Banks (Exhibit 99.1, NU Form 8-K dated December 9, 2005, File No. 1-5324)

(B)

The Connecticut Light and Power Company

4.1

Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921 (Composite including all twenty-four amendments to May 1, 1967) (Exhibit 4.1.1, 1989 CL&P Form 10-K, File No. 0-00404)

4.1.1

Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of October 1, 1994 (Exhibit 4.2.16, 1994 CL&P Form 10-K, File No. 0-00404)

4.1.2

Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of September 1, 2004 (Exhibit 99.2, CL&P Form 8-K filed September 22, 2004, File No. 0-00404)

4.1.3

Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5, CL&P Form 8-K filed September 22, 2004, File No. 0-00404)

4.2

Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company, dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005 (Exhibit 99.5, CL&P Form 8-K filed April 7, 2005, File No. 0-00404)

4.2.1

Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2, CL&P Form 8-K filed April 13, 2005, File No. 0-00404)

4.2.2

Supplemental Indenture (2006 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2006 (Exhibit 99.2, CL&P Form 8-K filed June 7, 2006, File No. 0-00404)

4.2.3

Supplemental Indenture (2007 Series A Bonds and 2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P 8-K filed March 27, 2007, File No. 0-00404)

4.2.4

Supplemental Indenture (2007 Series C Bonds and 2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2006 (Exhibit 4, CL&P 8-K filed September 17, 2007, File No. 0-00404)

E-2

4.3

Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986 (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246)

4.4

Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988 (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246)

4.5

Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992 (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246)

4.6

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.2.21, 1993 CL&P Form 10-K, File No. 0-00404)

4.7

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.2.22, 1993 CL&P Form 10-K, File No. 0-00404)

4.8

Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Bond - 1996A Series) dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Exhibit 4.2.24, 1996 CL&P Form 10-K, File No. 0-00404)

4.9

Amended and Restated Indenture of Trust between Connecticut Development Authority and the Trustee (CL&P Pollution Control Revenue Bond-1996A Series), dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Exhibit 4.2.24.1, 1996 CL&P Form 10-K, File No. 0-00404)

4.10

AMBAC Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond-1996A Series), effective January 23, 1997(Exhibit 4.2.24.3, 1996 CL&P Form 10-K, File No. 1-11419)

4.11

Compensation and Multiannual Mode Agreement among the Connecticut Development Authority and BNY Capital Markets, Inc. dated September 23, 2003 (Exhibit 4.2.7.5, CL&P Form 10-Q for the Quarter Ended September 30, 2003, File No. 0-00404)

4.12

Amended and Restated Receivables Purchase and Sale Agreement among CL&P and CL&P Receivables Corporation ("CRC") Corporate Asset Funding Company, Inc. ("CAFCO"), Citibank, N. A. ("Citibank") and Citicorp North America, Inc. ("CNAI"), dated as of March 30, 2001 (Exhibit 10.1, CL&P Form 10-Q for the Quarter Ended September 30, 2001, File No. 0-00404)

4.12.1

Amendment No. 2 to the Amended and Restated Receivables Purchase and Sale Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 10, 2002 (Exhibit 4.2.8.1, 2002 CL&P Form 10-K, File No. 0-00404)

4.12.2

Amendment No. 3 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 9, 2003 (Exhibit 4.2.8.2, CL&P Form 10-Q for the Quarter Ended September 30, 2003, File No. 0-00404)

4.12.3

Amendment No. 4 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 7, 2004 (Exhibit 4.12.3, CL&P Form 10-Q for the Quarter Ended June 30, 2005, File No. 0-00404)

4.12.4

Amendment No. 5 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 7, 2005 (Exhibit 4.12.4, CL&P Form 10-Q for the Quarter Ended June 30, 2005, File No. 0-00404)

4.12.5

Amendment No. 6 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 5, 2006 (Exhibit 4.12.5, CL&P Form 10-Q for the Quarter Ended June 30, 2006 File No. 0-00404)

E-3

4.12.6

Letter Amendment dated July 21, 2006 to Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 5, 2006 (Exhibit 4.12.6, CL&P Form 10-Q for the Quarter Ended September 30, 2006, File No. 0-00404)

4.12.7

Amendment No. 7 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO, Citibank, and CNAI, dated as of July 3, 2007 (Exhibit 4, CL&P Form 10-Q for the Quarter Ended June 30, 2007, File No. 0-00404)

4.13

Purchase and Contribution Agreement between CL&P and CRC, dated as of September 30, 1997 (Exhibit 10.49, 1997 CL&P Form 10-K, File No. 0-00404)

4.13.1

Amendment No. 1 to the Purchase and Contribution Agreement between CL&P and CRC dated as of March 30, 2001 (Exhibit 4.2.9, 2002 CL&P Form 10-K, File No. 0-00404)

4.13.2

Amendment No. 3 to the Purchase and Contribution Agreement between CL&P and CRC dated as of July 7, 2004 (Exhibit 4.13.2, 2006 CL&P Form 10-K, File No. 0-00404)

4.14

Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, CL&P Form 8-K dated December 9, 2005, File No. 0-00404)

(C)

Public Service Company of New Hampshire

4.1

First Mortgage Indenture dated as of August 15, 1978 between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, (Composite including all amendments to May 16, 1991) (Exhibit 4.4.1, 1992 PSNH Form 10-K, File No. 1-6392)

4.1.1

Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association, now First Union National Bank (Exhibit 4.1, PSNH Form 8-K dated February 10, 1992, File No. 1-6392)

4.1.2

Twelfth Supplemental Indenture dated as of December 1, 2001 between PSNH and First Union National Bank (Exhibit 4.3.1.2, 2001 PSNH Form 10-K, File No. 1-6392)

4.1.3

Thirteenth Supplemental Indenture, dated as of July 1, 2004, between PSNH and Wachovia Bank, National Association, successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2, PSNH Form 8-K filed October 5, 2004, File No. 1-6392)

4.1.4

Fourteenth Supplemental Indenture, dated as of October 1, 2005, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2, PSNH Form 8-K filed October 6, 2005, File No. 1-6392)

4.1.5

Fifteenth Supplemental Indenture, dated as of September 17, 2007, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 4.1, PSNH Form 8-K filed September 24, 2007, File No. 1-6392)

4.2

Series D (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999 (Exhibit 4.3.6, 1999 PSNH Form 10-K, File No. 1-6392)

4.3

Series E (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999 (Exhibit 4.3.7, 1999 PSNH Form 10-K, File No. 1-6392)

4.4

Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.4, 2001 PSNH Form 10-K, File No. 1-6392)

4.5

Series B Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.5, 2001 PSNH Form 10-K, File No. 1-6392)

E-4

4.6

Series C Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.6, 2001 PSNH Form 10-K, File No. 1-6392)

4.7

Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, PSNH Form 8-K dated December 9, 2005, File No. 1-6392)

(D)

Western Massachusetts Electric Company

4.1

Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Revenue Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.4.13, 1993 WMECO Form 10-K, File No. 0-7624)

4.2

Indenture between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)

4.2.1

First Supplemental Indenture between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)

4.2.2

Second Supplemental Indenture dated as of September 1, 2004, between WMECO and Bank of New York, as Trustee (Exhibit 4.1, WMECO Form 8-K filed September 27, 2004, File No. 0-7624)

4.2.3

Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Form 8-K filed August 12, 2005, File No. 0-7624)

4.2.4

Fourth Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Form 8-K filed August 17, 2007, File No. 0-7624)

4.3

Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, WMECO Form 8-K dated December 9, 2005, File No. 1-6392)

Material Contracts

(A)

10.1

Lease dated as of April 14, 1992 between The Rocky River Realty Company and Northeast Utilities Service Company with respect to the Berlin, Connecticut headquarters (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)

10.2

Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas Services Company and the Connecticut National Bank, as Trustee (Exhibit 4.7, Yankee Energy System, Inc. Form 10-K for the fiscal year ended September 30, 1990, File No. 0-10721)

10.2.1

First Supplemental Indenture of Mortgage and of Trust dated April 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee Yankee Energy System, Inc. (Registration Statement on Form S-3, dated October 2, 1992, File No. 33-52750)

10.2.2

Fourth Supplemental Indenture of Mortgage and Deed of Trust dated April 1, 1997 between Yankee Gas Services Company and Fleet National Bank (formerly The Connecticut National Bank), as Trustee (Exhibit 4.15, Yankee Energy System, Inc. Form 10-K for the fiscal year ended September 30, 1997, File No. 001-10721)

10.2.3

Fifth Supplemental Indenture of Mortgage and Deed of Trust dated January 1, 1999 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 4.2, Yankee Energy System, Inc. Form 10-Q for the fiscal quarter ended March 31, 1999, File No. 001-10721)

E-5

10.2.4

Sixth Supplemental Indenture and Deed of Trust dated January 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 10.5.6, 2004 NU Form 10-K, File No. 1-5324)

10.2.5

Seventh Supplemental Indenture and Deed of Trust dated November 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 10.5.7, 2004 NU Form 10-K, File No. 1-5324)

10.2.6

Eighth Supplemental Indenture and Deed of Trust dated July 1, 2005 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) (Exhibit 10.5.8, NU Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-5324)

*10.3

Summary of Trustee Compensation Arrangement

10.4

Northeast Utilities Deferred Compensation Plan for Trustees, amended and restated effective January 1, 2004 (Exhibit 10.32, NU Form 10-Q for the Quarter Ended March 31, 2004, File No. 1-5324)

10.4.1

Amendment No. 3 to Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2005 (Exhibit 10.24.1, 2005 NU Form 10-K, File No. 1-5324)

10.4.2

Amendment No. 4 to Northeast Utilities Deferred Compensation Plan for Trustees, effective September 12, 2006 (Exhibit 10.5.2, 2006 NU Form 10-K, File No. 1-5324)

10.5

Purchase and Sale Agreement dated as of May 1, 2006 between Select Energy, Inc. and Amerada Hess Corporation (Exhibit 10.32, NU Form 10-Q for the Quarter Ended March 31, 2006, File No. 1-5324)

10.6

Purchase and Sale Agreement dated July 24, 2006 between HWP and Mt. Tom Generating Company LLC (Exhibit 10.33, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.6.1

Guaranty dated July 24, 2006 of NU for the benefit of Mt. Tom Generating Company LLC (Exhibit 10.33.2, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.7

Stock Purchase Agreement dated July 24, 2006 between NU Enterprises and NE Energy, Inc. (Exhibit 10.34, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.7.1

Guaranty dated July 24, 2006 of NU for the benefit of NE Energy, Inc. (Exhibit 10.34.2, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.8

Purchase and Sale Agreement dated July 24, 2006 by and among NGS, Select Energy, Northeast Utilities Service Company on the one hand, and NE Energy, Inc. on the other hand (Exhibit 10.35, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.8.1

Guaranty dated July 24, 2006 of NU for the benefit of NE Energy, Inc. (Exhibit 10.35.2, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.9

Stock Purchase Agreement dated as of February 1, 2006 by and among Ameresco, Inc. ("Ameresco"), NU Enterprises and NU (Exhibit 10.36, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.9.1

Stock Purchase Agreement Amendment and Waiver dated as of May 5, 2006 among NU Enterprises, NU and Ameresco (Exhibit 10.36.3, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.9.2

NU Indemnification Agreement dated as of May 5, 2006 (Exhibit 10.36.4, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.9.3

Agreement to Purchase Contract Payments dated as of May 5, 2006 among NU, Ameresco and General Electric Capital Corporation (Exhibit 10.36.5, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

(B)

NU, CL&P, PSNH and WMECO

E-6

10.1

Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO) (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324)

10.1.1

Form of Amendment and Renewal of Service Contract dated as of January 1, 2007 (Exhibit 10.2, 2006 NU Form 10-K, File No. 1-5324)

*10.1.2

Form of Amendment and Renewal of Service Contract dated as of January 1, 2008

10.2

Stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company (CYAPC) (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)

10.3

Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324)

10.4

Power Purchase Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324)

10.5

Additional Power Purchase Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)

10.6

Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-5324)

10.7

Form of 1996 Amendatory Agreement between CYAPC and CL&P dated December 4, 1996 (Exhibit 10 (B) 10.9, 2003 NU Form 10-K, File No. 1-5324)

10.7.1

Form of First Supplemental to the 1996 Amendatory Agreement dated as of February 10, 1997 (Exhibit 10 (B) 10.9.1, 2003 NU Form 10-K, File No. 1-5324)

10.8

Amended and Restated Additional Power Contract between CYAPC and purchasers named therein, dated as of April 30, 1984 and restated as of July 1, 2004) (Exhibit 10.9.3, 2004 NU Form 10-K, File No. 1-5324)

10.8.1

Revision to Attachment B to Amended and Restated Additional Power Contract, dated as of April 30, 1984, issued on August 15, 2007 and effective January 1, 2007 (as contained in Settlement Agreement dated August 15, 2006 among CYAPC, Connecticut Department of Public Utility Control, Connecticut Consumer Counsel, Maine Public Advocate and Maine Public Utility Commission, filed with the Federal Energy Regulatory Commission on August 15, 2006 in Dockets Nos. ER04-981-000 and EL04-109-000) (Exhibit 10.10.1, 2006 NU Form 10-K, File No. 1-5324)

10.9

2000 Amendatory Agreement between CYAPC and CL&P dated as of July 28, 2000 (Exhibit 10.9.2, 2004 NU Form 10-K, File No. 1-5324)

10.10

Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)

10.11

Amended and Restated Power Purchase Contract dated as of April 1, 1985, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324)

10.11.1

Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)

10.11.2

Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)

10.11.3

Amendment No. 6 to Power Contract, dated July 1, 1989, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)

10.11.4

Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324)

E-7

10.11.5

Form of Amendment No. 8 to Power Contract, dated June 1, 2003, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10 (B) 10.11.5, 2003 NU Form 10-K, File No. 1-5324)

10.11.6

Form of Amendment No. 9 to Power Contract, dated November 17, 2005, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.11.6, 2005 NU Form 10-K, File No. 1-5324)

10.11.7

Form of Amendment No. 10 to Power Contract, dated April 14, 2006 between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.11.7, NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)

10.12

Stockholder Agreement dated as of May 20, 1968, among stockholders of MYAPC (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)

10.13

Capital Funds Agreement dated as of May 20, 1968 between MYAPC and CL&P, PSNH, HELCO and WMECO (Exhibit 10.8, 1997 NU Form 10-K, File No. 1-5324)

10.13.1

Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)

10.14

Power Purchase Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO (Exhibit 10.7, 1997 Form 10-K, File No. 1-5324)

10.14.1

Amendment No. 1 to Power Contract dated as of March 1, 1983 between MYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324)

10.14.2

Amendment No. 2 to Power Contract dated as of January 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-5324)

10.14.3

Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1-5324)

10.15

Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)

10.16

1997 Amendatory Agreement dated as of August 6, 1997 between MYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.14.5, 2005 NU Form 10-K, File No. 1-5324)

10.17

Composite Conformed Rate Schedule 2004 reflecting the operative provisions of: I. Additional Power Contract dated as of February 1, 1984, II. 1997 Amendatory Agreement dated as of August 6, 1997, III. Settlement Agreement in Docket No. ER-04-55-000 and IV. Formula Rate (Exhibit 10.19, 2006 NU Form 10-K, File No. 1-5324)

10.18

Agreements among New England Utilities with respect to the Hydro-Quebec interconnection projects (Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.)

10.19

Transmission Operating Agreement dated as of February 1, 2005 between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. (Exhibit 10.29, 2004 NU Form 10-K, File No. 1-5324)

10.19.1

Rate Design and Funds Disbursement Agreement, effective June 30, 2006 among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. (Exhibit 10.22.1, 2006 NU Form 10-K, File No. 1-5324)

10.20

Employment Agreement with Cheryl W. Grisé, dated as of April 1, 2003 (Exhibit 10.45.6, NU Form 10-Q for Quarter Ended March 31, 2003, File No. 1-5324)

10.20.1

Terms of Separation arrangements for Cheryl W. Grisé (Exhibit 10.24.1, 2006 NU Form 10-K, File No. 1-5324)

E-8

*10.20.2

Separation Agreement with Cheryl W. Grisé, dated as of June 22, 2007

10.21

Employment Agreement with Charles W. Shivery dated as of March 31, 2005 (Exhibit 10.24.2, NU Form 10-Q for the Quarter Ended March 31, 2005, File No. 1-5324)

10.22

Employment Agreement with Gregory B. Butler, dated as of October 1, 2003 (Exhibit 10 (B) 10.31, 2003 NU Form 10-K, File No. 1-5324)

10.23

Employment Agreement with David R. McHale dated as of March 31, 2005 (Exhibit 10.30, NU Form 10-Q for the Quarter Ended March 31, 2005, File No. 1-5324)

10.24

Description of terms of employment of Leon J. Olivier (Exhibit 10 (C) 10.3, 2003 NU Form 10-K, File No. 1-5324)

10.25

NU Incentive Plan, effective as of January 1, 1998 (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)

10.25.1

Amendment to NU Incentive Plan, effective as of February 23, 1999 (Exhibit 10.35.1.1, 1998 NU Form 10-K, File No. 1-5324)

10.25.2

Amendment 2 to NU Incentive Plan, effective as of September 12, 2006 (Exhibit 10.29.2, 2006 NU Form 10-K, File No. 1-5324)

*10.26

Amended and Restated NU Incentive Plan, effective as of May 9, 2007

10.27

Supplemental Executive Retirement Plan for Officers of NU System Companies, Amended and Restated effective as of January 1, 1992 (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324)

10.27.1

Amendment 1 to Supplemental Executive Retirement Plan, effective as of August 1, 1993 (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324)

10.27.2

Amendment 2 to Supplemental Executive Retirement Plan, effective as of January 1, 1994 (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324)

10.27.3

Amendment 3 to Supplemental Executive Retirement Plan, effective as of January 1, 1996 (Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324)

10.27.4

Amendment 4 to Supplemental Executive Retirement Plan, effective as of February 26, 2002 (Exhibit 10.35.4, 2001 NU Form 10-K, File No. 1-5324)

10.27.5

Amendment 5 to Supplemental Executive Retirement Plan, effective as of November 1, 2001 (Exhibit 10.35.5, 2001 NU Form 10-K, File No. 1-5324)

10.27.6

Amendment 6 to Supplemental Executive Retirement Plan, effective as of December 9, 2003 (Exhibit 10 (B) 10.18.6, 2003 NU Form 10-K, File No. 1-5324)

10.27.7

Amendment 7 to Supplemental Executive Retirement Plan, effective as of February 1, 2005 (Exhibit 10.18.7, 2004 NU Form 10-K, File No. 1-5324)

10.27.8

Amendment 8 to Supplemental Executive Retirement Plan, effective as of January 1, 2006 (Exhibit 10.30.8, 2006 NU Form 10-K, File No. 1-5324)

*10.27.9

Amendment No. 9 to Supplemental Executive Retirement Plan, effective as of January 1, 1992

10.28

Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 NU Form 10-K, File No. 1-5324)

10.28.1

First Amendment to Trust, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 NU Form 10-K, File No. 1-5324)

10.29

Special Severance Program for Officers of NU System Companies, as adopted on July 15, 1998 (Exhibit 10.37, 1998 NU Form 10-K, File No. 1-5324)

E-9

10.29.1

Amendment to Special Severance Program, effective as of February 23, 1999 (Exhibit 10.37.1, 1998 NU Form 10-K, File No. 1-5324)

10.29.2

Second Amendment to Special Severance Program, effective as of September 14, 1999 (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324)

10.29.3

Amendment 3 to Special Severance Program, effective September 12, 2006 (Exhibit 10.32.3, 2006 NU Form 10-K, File No. 1-5324)

10.30

Northeast Utilities Deferred Compensation Plan for Executives, amended and restated effective January 1, 2004 (Exhibit 10.33, NU Form 10-Q for the Quarter Ended March 31, 2004, File No 1-5324)

10.30.1

Amendment No. 1 to Northeast Utilities Deferred Compensation Plans for Executives, effective January 1, 2005 (Exhibit 10.25.1, 2005 NU Form 10-K, File No. 1-5324)

10.30.2

Amendment No. 2 to Northeast Utilities Deferred Compensation Plans for Executives, effective September 12, 2006 (Exhibit 10.33.2, 2006 NU Form 10-K, File No. 1-5324)

10.30.3

Amendment No. 3 to Northeast Utilities Deferred Compensation Plans for Executives, effective January 1, 2006 (Exhibit 10.33.3, 2006 NU Form 10-K, File No. 1-5324)

10.31

Northeast Utilities System's Second Amended and Restated Tax Allocation Agreement dated as of September 21, 2005 (Exhibit D.4 to Amendment No. 1 to U5S Annual Report for the year ended December 31, 2004, filed September 30, 2005, File No. 1-5324)

(C)

NU and CL&P

10.1

CL&P Transition Property Purchase and Sale Agreement between CL&P Funding LLC and CL&P, dated as of March 30, 2001 (Exhibit 10.55, 2001 CL&P Form 10-K, File No. 0-11419)

10.2

CL&P Transition Property Servicing Agreement CL&P Funding LLC and CL&P, dated as of March 30, 2001 (Exhibit 10.56, 2001 CL&P Form 10-K, File No. 0-11419)

(D)

NU and PSNH

10.1

PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.57, 2001 PSNH Form 10-K, File No. 1-6392)

10.2

PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.58, 2001 PSNH Form 10-K, File No. 1-6392)

10.3

PSNH Purchase and Sale Agreement with PSNH Funding LLC2 dated as of January 30, 2002 (Exhibit 10.59 2001 PSNH Form 10-K, File No. 1-6392)

10.4

PSNH Servicing Agreement with PSNH Funding LLC2 dated as of January 30, 2002 (Exhibit 10.60, 2001 PSNH Form 10-K, File No. 1-6392)

(E)

NU and WMECO

10.1

Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina (Exhibit 10.63, 1988 WMECO Form 10-K, File No. 0-7624)

10.2

WMECO Transition Property Purchase and Sale Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.61, 2001 WMECO Form 10-K, File No. 0-7624)

10.3

WMECO Transition Property Servicing Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.62, 2001 WMECO Form 10-K, File No. 0-7624)

E-10

*12

Ratio of Earnings to Fixed Charges

*13

Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K of that respective registrant)

*13.1

Annual Report of CL&P

*13.2

Annual Report of WMECO

*13.3

Annual Report of PSNH

*21

Subsidiaries of the Registrant

*23

Consent of Independent Registered Public Accounting Firm

*31

Rule 13-a - 14(a)/15 d - 14(a) Certifications

(A)

Northeast Utilities

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of NU required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of NU required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

(B)

The Connecticut Light and Power Company

Certification of Leon J. Olivier, Chief Executive Officer of CL&P required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of CL&P required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

(C)

Public Service Company of New Hampshire

Certification of Leon J. Olivier, Chief Executive Officer of PSNH required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of PSNH required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

(D)

Western Massachusetts Electric Company

Certification of Leon J. Olivier, Chief Executive Officer of WMECO required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of WMECO required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

E-11

*32

Section 1350 Certificates

(A)

Northeast Utilities

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, and David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

(B)

The Connecticut Light and Power Company

Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and David R. McHale, Senior Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

(C)

Public Service Company of New Hampshire

Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and David R. McHale, Senior Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

(D)

Western Massachusetts Electric Company

Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and David R. McHale, Senior Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 28, 2008

E-12